North America Shale Bloghttp://www.northamericashaleblog.com
Tue, 31 Mar 2015 18:16:23 +0000en-UShourly1http://wordpress.org/?v=4.0.1Hydraulic Fracturing Moratorium Lifted in North Carolinahttp://feeds.lexblog.com/~r/northamericashaleblog/~3/vChFAR05wDs/
http://www.northamericashaleblog.com/2015/03/30/hydraulic-fracturing-moratorium-lifted-in-north-carolina/#commentsMon, 30 Mar 2015 13:00:47 +0000http://www.northamericashaleblog.com/?p=2827Continue Reading]]>Last week, North Carolina became the 34th state to allow hydraulic fracturing. Years in the making, new rules developed by the state’s Mining and Energy Commission after receiving over 200,000 public comments went into effect last Tuesday allowing the state to issue drilling permits to companies to begin shale gas exploration and extraction. The new rules open the door for drilling to begin in North Carolina later this year. The new rules govern many aspects of drilling, including well construction, water testing and buffer zones. Officials from the Mining and Energy Commission indicated that any company interested in fracing would have to establish a “drilling unit” by acquiring the mineral rights associated with several hundred acres of land before being able to apply for a drilling permit.

James Womack, a member of the Mining and Energy Commission, anticipates that some drilling will occur by the end of the year, although it may be some time before full-scale unconventional drilling operations are established, as more exploration may be needed before major, established oil and energy companies are willing to commit to the large investment necessary to implement a full-scale operation.

Although the quantity of natural gas in North Carolina is still unknown, some think it could be as much as in nearby states like Pennsylvania. In addition, potential fracing hot spots have previously been identified by maps published by the N.C. Geological Survey. Shale gas is thought to be concentrated in an approximately 90-square-mile area spanning Lee, Chatham and Moore counties in rural North Carolina to the southwest of Raleigh.

The Southern Environmental Law Center, on behalf of a conservation group and a landowner in Lee County, has already challenged the rules in court, arguing the formation of the Mining and Energy Commission violates the separation of powers provisions of the North Carolina state constitution. The lawsuit is pending while a panel of judges is selected to hear the case.

]]>http://www.northamericashaleblog.com/2015/03/30/hydraulic-fracturing-moratorium-lifted-in-north-carolina/feed/0http://www.northamericashaleblog.com/2015/03/30/hydraulic-fracturing-moratorium-lifted-in-north-carolina/Crude-by-Rail Still Outcompetes Pipelines in the Bakkenhttp://feeds.lexblog.com/~r/northamericashaleblog/~3/ISvRCE0uUXg/
http://www.northamericashaleblog.com/2015/03/27/crude-by-rail-still-outcompetes-pipelines-in-the-bakken/#commentsFri, 27 Mar 2015 18:53:07 +0000http://www.northamericashaleblog.com/?p=2822Continue Reading]]>With low oil prices and producers slashing the rig count in the Bakken shale, it is fair to ask whether crude-by-rail will be able to compete with pipelines in the region. The bottom line is that crude-by-rail is likely to continue playing a vital role in carrying large amounts of crude—more than 700 thousand barrels per day (kbd) or roughly 10 unit trains’ worth per day—out of the Bakken area.

Aggregating the existing crude-by-rail loading facilities and export pipelines in the Bakken area indicates that there are currently approximately 1,360 kbd of rail and 750 kbd of pipeline takeaway capacity (Exhibit 1). Rail capacity could rise to 1,500 kbd over the next three years, primarily from expansion of existing facilities, while pipeline capacity could increase to 1,300 kbd by year-end 2018. In short, the vast majority of potential outbound rail capacity is already “baked in” and pipelines are where capacity could grow sharply if planned projects come through.

Exhibit 1: Bakken Crude Takeaway Capacity

kbd
Source: Company Reports, NDPA, Author’s Estimate

Low-cost, flexible rail is well-suited to operate in a volatile, spot market environment. Pipelines, however, are ill-suited because they are very expensive and need to be run at high-capacity utilization rates to pay back project financing costs. Crude-by-rail loading facilities large enough to load unit trains can be built for as little as $0.6 million per 1,000 barrels per day of loading capacity.[1] In contrast, large long-distance oil pipelines can cost $15 million per 1,000 barrels per day of throughput capacity.[2]

Planned Bakken Pipeline Capacity Is More Exposed to Oil Market Risk Than Rail Terminals Are

Major new pipeline projects are unlikely to come online for at least 18 months, leaving them exposed to oil price volatility and other macroeconomic forces. This in turn raises the risk that the projects could be scaled down, deferred, or possibly even cancelled as a planned 340 kbd line linking the Bakken to Cushing, Oklahoma, was in December 2014.[3]

Pipeline projects moving Bakken crude to the Midwest face three core challenges. First, they take large volumes of oil farther from the West Coast, a significant market for Bakken crude that will expand further once Tesoro and Savage complete their 360 kbd rail unloading terminal in Vancouver, Washington.[4] Second, they add time to—but likely do not sufficiently reduce the cost of—the trip to the East Coast refineries that are the biggest consumers of Bakken crude. Finally, the lines would generally feed into logistical corridors that are oriented toward moving crude oil to the Gulf Coast market, which is already saturated with local light, sweet production and will only become more so as the Permian Basin continues to switch to horizontal drilling and development of multilayer frac plays.

Crude-by-Rail Remains Competitive Despite Low Oil Prices

The North Dakota Pipeline Authority’s estimates of how Bakken and Williston Basin crude gets to market—broken down between pipeline, rail, local refining, and trucking—presents a fascinating and illuminating picture. In early 2012, when the NDPA began tracking shipment proportions, rail accounted for less than 30 percent of crude hauls but rose rapidly over the course of the next year and a half as refiners demanded more supplies of bottlenecked and deeply discounted Bakken crude (Exhibit 2).

Exhibit 2: Modes by Which Bakken/Williston Basin Crude Gets to Market

(percent of total crude oil produced in basin)

Source: EIA, NDPA

Since mid-2013, the pipeline/rail proportion has swung back and forth as the two modes compete with one another for barrels, with relatively more oil traveling out by pipe when WTI crude oil’s price discount to Brent narrows. But even after the oil price crash, rail still carried 58 percent of crude shipments out of the Bakken area in January 2015. Rail’s staying power has been remarkable, driven primarily by the facts that (1) no pipelines exist to carry Bakken crude to East and West Coast refineries, and (2) rail allows refineries a greater range of options for sourcing a variety of crudes on short notice without onerous long-term contracts like those which pipelines would impose.

The Most Competitive Bakken Crude-by-Rail Facilities Will Gain Ground

If oil prices remain low, the most competitive rail loading terminals will be the unit train-capable facilities which are located near the Bakken’s most productive acreage in Dunn, McKenzie, Mountrail, and Williams counties, as well as those facilities with access to gathering pipelines.[5] Direct access to gathering pipeline networks offers key benefits, including lower gathering costs, higher efficiency, less exposure to severe winter weather that can disrupt trucking operations, and greater ability to monitor and control the quality of crude oil headed into the facility. Facilities that score high on these metrics include Crestwood Midstream Partners’ COLT Hub, EOG Resources’ Stanley terminal, and BOE Midstream’s Dickinson terminal.

Bakken Crude-by-Rail Is a Long-Term Proposition

A top refining executive’s recent public statements suggest an optimistic future for crude-by-rail from the Bakken. Thomas O’Malley, the executive chairman of PBF Energy, which accounts for nearly 30 percent of U.S. East Coast refining capacity, said in the company’s October 30, 2014, investor call that he believes rail out of the Bakken is a “long term operation” and that “rail is going to be a long term proposition to the US East Coast.”[6]

]]>http://www.northamericashaleblog.com/2015/03/27/crude-by-rail-still-outcompetes-pipelines-in-the-bakken/feed/0http://www.northamericashaleblog.com/2015/03/27/crude-by-rail-still-outcompetes-pipelines-in-the-bakken/State of Wyoming Joins Independent Producers In Opposition To Federal Hydraulic Fracturing Rulehttp://feeds.lexblog.com/~r/northamericashaleblog/~3/flQZV_vzd1M/
http://www.northamericashaleblog.com/2015/03/26/state-of-wyoming-joins-independent-producers-in-opposition-to-federal-hydraulic-fracturing-rule/#commentsThu, 26 Mar 2015 17:18:08 +0000http://www.northamericashaleblog.com/?p=2820Continue Reading]]>The Wyoming Attorney General’s Office filed a complaint today in Wyoming federal district court asking the court to set aside recently finalized federal regulations related to hydraulic fracturing on federal and public lands. Wyoming’s complaint requests the court set aside regulations the United States Department of the Interior announced last Friday, the same relief sought in a complaint that BakerHostetler previously filed in the same court on behalf of the Independent Petroleum Association of America (“IPAA”) and Western Energy Alliance. Wyoming becomes the first state to challenge the rule. A copy of Wyoming’s Complaint is available here.

According to the Bureau of Land Management’s Public Land Statistics, more than 1,000 permits were approved on federal oil and gas leases located within Wyoming during each of the last two fiscal years for which data is available. At the conclusion of Fiscal Year 2013, Wyoming had more than 4 million federal acres designated as being in producing status. Wyoming leads the nation in both categories. Wyoming is also a leader in regulating oil and gas development. During recent testimony before the Senate Committee on Energy & Natural Resources, Secretary of the Interior Sally Jewell praised Wyoming’s hydraulic fracturing regulations, acknowledging that “Wyoming has done a very good job in providing regulations that are forward thinking.”[1]According to the Petroleum Association of Wyoming, Wyoming’s petroleum industry contributed almost $2 billion in tax and royalty revenues to state and local governments in fiscal year 2013.[2] “Wyoming’s interest in this lawsuit is obvious,” stated BakerHostetler attorney Mark Barron, part of the legal team representing IPAA in independent producers’ analogous challenge to the Interior Department’s new rules. Barron continued: “The State’s leadership in regulating oil and gas development, and particularly the process of hydraulic fracturing, disproves the myth of the regulatory gap upon which Interior’s final rule is premised. Wyoming’s willingness to fight these regulations in federal court is evidence of the extent to which Interior’s action represents regulatory overreach and an untenable infringement on state sovereignty.”

]]>http://www.northamericashaleblog.com/2015/03/26/state-of-wyoming-joins-independent-producers-in-opposition-to-federal-hydraulic-fracturing-rule/feed/0http://www.northamericashaleblog.com/2015/03/26/state-of-wyoming-joins-independent-producers-in-opposition-to-federal-hydraulic-fracturing-rule/California Crude Trains: How Much Oil Is Actually Coming In and Where Is It Coming From?http://feeds.lexblog.com/~r/northamericashaleblog/~3/g4Ac1S845ds/
http://www.northamericashaleblog.com/2015/03/23/california-crude-trains-how-much-oil-is-actually-coming-in-and-where-is-it-coming-from/#commentsMon, 23 Mar 2015 13:32:21 +0000http://www.northamericashaleblog.com/?p=2810Continue Reading]]>California has become ground zero for legal opposition to crude-by-rail projects. Opponents decry derailments, toxic vapors, and other ills.[i] Yet despite the dire images painted by crude-by-rail’s opponents, the reality on the ground in California has been quite mundane thus far. The high-water mark to date for California railborne crude supplies was approximately 39 thousand barrels of oil per day (kbd) in December 2013 (Exhibit 1). To put this number in perspective, California refineries typically process an average of around 1.7 million barrels per day of crude – meaning that at the crude-by-rail peak, only about one barrel in 50 of the state’s crude supply came in by rail.[ii] Presently, the number is closer to one barrel in 100 – certainly not the overwhelming flood of trains opponents fear. And to that point, even supplying one-quarter of California’s total crude oil needs would only require about six to seven crude oil unit trains per day. To put this in context, the Colton Crossing east of Los Angeles by itself can see more than 100 freight trains per day.[iii]

For much of the past six years, light, low-sulfur Bakken crude and heavier, higher-sulfur Western Canadian Select (“WCS”) dominated rail imports into California. Canadian supplies show a clear correlation with how cheap WCS is relative to Maya, a heavy crude oil from Mexico that is shipped by tanker and offers a proxy for what heavy, sour, waterborne crude oil imports into California will cost. The spread between WCS and Maya prices matters because it only makes sense for refiners to purchase WCS barrels if they are sufficiently discounted that the buyer still comes out ahead after adjusting for rail transport costs, which can amount to approximately $20/barrel for manifest trains and $15/barrel for oil moved on unit trains.[iv]

For reference, “manifest trains” are mixed cargo trains where a 100-car freight train might include 20 or 30 tanker cars carrying oil. Unit trains, on the other hand, carry only one type of freight, meaning that all 100 to 120 cars carry crude oil. This maximizes economies of scale and significantly reduces transportation costs. Shipments of Canadian crude oil into California traditionally rode on manifest trains, but in November 2014, Union Pacific brought its first unit train of crude oil from Western Canada into California, to a terminal near Bakersfield.[v] The route is currently dormant as WCS crude’s discount to Maya was less than $10 per barrel in January 2015, according to official price data, making it uneconomical to import the Canadian oil by rail.[vi] Unit trains’ lower costs relative to the previously used manifest trains will likely have oil trains rolling from Alberta to California once again if the WCS discount widens to around $15 per barrel.

California has also seen increased supplies of light, low-sulfur crude oil from New Mexico in recent months. The most likely explanation for this is that continued strong oil production in Texas, New Mexico, and the Midcontinent are inundating the Gulf Coast with light, sweet barrels. Indeed, this author’s models using official Energy Information Administration data strongly suggest that Gulf Coast refineries have hit a physical “wall” where they are not able to sustainably use more than 65 percent domestic crude oil to supply their plants, because facilities designed for heavier, higher-sulfur oils cannot run at maximal efficiency with light, low-sulfur crude feedstocks.[vii] This crowded market reduces the potential realized value of crude to certain Permian Basin producers and makes California attractive as a clearing destination because crude can be railed from the Permian Basin to California for as little as $7-8/bbl, according to Tesoro.[viii]

What the Future May Hold

The bottom line is that California’s existing crude-by-rail terminal capacity is massively underutilized at present. The state’s two largest facilities alone – Kinder Morgan’s terminal at Richmond and Plains All American’s new terminal near Bakersfield – can offload more than 140 kbd at full capacity. In comparison, crude-by-rail import volumes were less than 20 kbd in December 2014, the last month for which data are available (Exhibit 2).

Current terminal capacity is sufficient for approximately two unit trains per day of crude – 140 to 150 kbd – to enter the state. California’s fickle politics make forecasting crude-by-rail volumes a tough exercise. That said, this author believes that if oil prices recover to at least $75/bbl, California’s railborne crude imports will likely exceed 200 kbd by early 2016. Under those conditions, existing terminals would increase their capacity utilization and larger price differentials would attract additional Canadian heavy crude, as well as Bakken and other light, sweet grades from the Rocky Mountain states and the Permian

]]>http://www.northamericashaleblog.com/2015/03/23/california-crude-trains-how-much-oil-is-actually-coming-in-and-where-is-it-coming-from/feed/0http://www.northamericashaleblog.com/2015/03/23/california-crude-trains-how-much-oil-is-actually-coming-in-and-where-is-it-coming-from/Independent Producers Lead Legal Challenge Against BLM’s Hydraulic Fracturing Rulehttp://feeds.lexblog.com/~r/northamericashaleblog/~3/6Ajr9c8O5U0/
http://www.northamericashaleblog.com/2015/03/20/independent-producers-lead-legal-challenge-against-blms-hydraulic-fracturing-rule/#commentsFri, 20 Mar 2015 18:25:01 +0000http://www.northamericashaleblog.com/?p=2807Continue Reading]]>After a regulatory review process lasting more than three years, the Bureau of Land Management (BLM) issued today a final rule purporting to govern hydraulic fracturing on federal and Indian lands. Given BLM’s failure to correct flaws in earlier versions of the rule – flaws that were addressed expressly in public comments responsive to the agency’s proposal — BakerHostetler immediately filed a lawsuit in federal court on behalf of the two most prominent national trade associations representing independent oil and gas producers: the Independent Petroleum Association of America (IPAA) and Western Energy Alliance (the Alliance). The associations’ Complaint, filed in the United States District Court for the District of Wyoming, asserts that BLM’s final rule is both substantively meritless and the product of a procedurally deficient rulemaking process. The Complaint requests that the federal court set aside the final rule.

Independent oil and gas producers note several factors that undermine the legitimacy of BLM’s approach. Most important, even were another layer of administrative rules necessary to ensure that hydraulic fracturing can be conducted safely, a position that contravenes decades of technical evidence, BLM’s new regulations do not represent those rules. Despite being titled as a rule for “Hydraulic Fracturing on Federal and Indian Lands,” BLM’s proposal does not attempt to govern any aspect of the hydraulic fracturing process. This omission suggests little more than a politically-motivated attempt to appeal to those that misrepresent “hydraulic fracturing,” using the term as a proxy for all oil and gas development rather than focusing on the more accurate, and narrower, definition of the term as a well stimulation technique.

What is included in the final rule are new regulations imposing administrative impediments that will complicate and frustrate oil and gas production on federal lands. BLM has included cementing and construction standards that it contends will ensure well bore integrity, but which simply duplicate existing state regulations and industry best practices. The agency will now require public disclosure of chemical additives injected during production operations, mirroring requirements that already exist under state law. But unlike the states, BLM will now also require operators to disclose highly confidential operational and engineering design information in a manner that disregards the prohibitions against such disclosures under federal public records laws. And BLM’s proposal will impose rigid requirements for the methods that may be used to manage and store water produced during oil and gas operations, regardless of whether that storage method represents the most environmentally sensitive method of managing produced water.

“Independent producers operate in a responsible manner that protects the nation’s public lands, but the rule BLM has promulgated provides no public benefit. Requiring oil and gas operators to file repetitive paperwork with multiple government agencies will not prevent or remediate environmental harm,” said Mark Barron, a Denver-based attorney in BakerHostetler’s Energy and Shale practice team. “To the contrary, if implemented the rule will rob oil and gas operators of the operational flexibility needed to ensure that the environmental footprint of development is reduced to the greatest extent possible.”

America’s oil and gas producers consider it telling that BLM fails to identify a single environmental problem related to hydraulic fracturing that persists under state law but that the new rule would remediate; or list a single incident that the new federal rules would have prohibited, but which was not covered under existing state rules.

Oil and natural gas operators will not be the only ones negatively affected should the new regulations be implemented. While the amount of oil and gas extracted from American wells has increased steadily over the last decade (the United States is poised to become the world’s leading producer of hydrocarbons), the percentage of that production extracted from federal lands has declined for most of the same period. A complex network of regulatory requirements – both existing and proposed – as well as logistical inefficiencies inherent in the federal government’s management of the nation’s public lands represent an enormous incentive for operators to focus their efforts on state and private lands. With the issuance of this rule, BLM has now exacerbated this incentive.

“The results are not difficult to predict: more rigs moving off federal lands, fewer jobs and reduced economic growth in the western public lands states, and less revenue flowing into the federal treasury,” said L. Poe Leggette, co-leader of the firm’s Energy and Shale practice team.

“With the lawsuit filed today, IPAA and the Alliance have taken an essential step toward continuing the environmentally responsible development of resources that contribute to domestic security and America’s economic well-being,” added Barron. “Working with our partners in the private sector, as well as within state and tribal governments, we remain committed to supporting the associations’ members and repelling government overreach that undermines those objectives.”

A copy of the Complaint that BakerHostetler filed in the United States District Court for the District of Wyoming is available here.

On February 23, 2015, Judge Mariani of the U.S. District Court for the Middle District of Pennsylvania denied Citizens for Pennsylvania’s Future’s (PennFuture) claim that Ultra Resources, Inc. (Ultra), was operating its natural gas compressor stations on the Marcellus Shale without the necessary permit. Although Ultra’s eight separate compressor stations – facilities that compress and pump gas from the wells to processing facilities – each had general permits, PennFuture claimed that the compressor stations should be aggregated and therefore require a more stringent major source permit. While Ultra had obtained general permits from the Pennsylvania Department of Environmental Protection (DEP) that cover “aspects of natural gas compression and processing operation,” if the court determined that the eight stations should be aggregated then they would require a major source permit since they could potentially produce over 100 tons of nitrous oxide per year.

The court’s analysis of whether Ultra’s eight compression facilities should be aggregated hinged on an interpretation of whether the facilities were “adjacent” to one another. Under Pennsylvania air permitting regulations, sources of air contamination may be aggregated if they are on contiguous or adjacent properties under common control. This was a matter of first impression for the Third Circuit, and the court relied on the Sixth Circuit’s literal interpretation of adjacent in Summit Petroleum Corp. v. U.S. Environmental Protection Agency. Ultra’s compression stations were not adjacent under the plain meaning of the term since some parcels were separated by miles. After the Summit Petroleum decision, however, the DEP issued guidance that noted that while the spatial relationship is the preeminent factor in a determination of adjacency, “functional interdependence” could be considered as well. Here, the court denied PennFuture’s claim that Ultra’s compression facilities are functionally related, but the court notably left functional interdependence as a possible, secondary consideration in future determinations of whether facilities are adjacent to one another.

]]>http://www.northamericashaleblog.com/2015/03/17/district-court-rejects-claim-to-aggregate-series-of-compressor-stations/feed/0http://www.northamericashaleblog.com/2015/03/17/district-court-rejects-claim-to-aggregate-series-of-compressor-stations/Texas Legislature Takes Further Aim at Local/Municipal Fracking Banshttp://feeds.lexblog.com/~r/northamericashaleblog/~3/FOe0a_Al8us/
http://www.northamericashaleblog.com/2015/03/12/texas-legislature-takes-further-aim-at-localmunicipal-fracking-bans/#commentsThu, 12 Mar 2015 20:48:07 +0000http://www.northamericashaleblog.com/?p=2803Continue Reading]]>On Tuesday, March 11, 2015, the Texas Legislature’s 84th Session gained another bill directed at combating future local and municipal fracking bans. State Rep. Drew Darby (R-San Angelo), Chairman of the Texas House Energy Resources Committee, filed House Bill 40 (HB40), which seeks to amend Chapter 81 of the Texas Natural Resources Code and expressly preempts the authority of “a municipality or other political subdivision” to regulate an “oil and gas operation” and gives exclusive jurisdiction to regulate an “oil and gas operation” to the state of Texas, specifically the Railroad Commission.

Under the terms of HB40, a municipality or other political subdivision would not be able to “enforce an ordinance or other measure, or an amendment or revision of an existing ordinance or other measure, that bans, limits, or otherwise regulates an oil and gas operation within its boundaries or extraterritorial jurisdiction.” HB40 defines an “oil and gas operation” as “an activity associated with the exploration, development, production, processing, and transportation of oil and gas, including drilling, hydraulic fracture stimulation, completion, maintenance, reworking, recompletion, disposal, plugging and abandonment, secondary and tertiary recovery techniques, and remediation activities.”

The bill does dictate that municipalities and political subdivisions retain authority to “enact, amend, or enforce an ordinance or other measure that regulates only surface activity that is incident to an oil and gas operation, is commercially reasonable, does not effectively prohibit an oil and gas operation, and is not otherwise preempted by state or federal law.” The bill defines “commercially reasonable” as “a condition that permits a reasonably prudent operator to fully, effectively, and economically exploit, develop, produce, process, and transport oil and gas.”

Rep. Darby’s office has stated, though, that the bill is not retroactive and would not overturn the ban on hydraulic fracturing adopted by Denton last November. The issue of state preemption in the area of oil and gas regulation is the crux of the lawsuits filed against the city of Denton by the Texas General Land Office and Texas Oil and Gas Association last year in Travis County and Denton County, respectively. Although HB40 would not directly resolve those matters, its adoption would be the strongest signal yet from the Texas Legislature on the issue of local versus statewide regulation of the oil and gas industry.

In follow-up to the January 22, 2015, post regarding HB539 and HB540, both of which also address local/municipal hydraulic fracturing bans, HB539 has been referred to the House Energy Resources Committee, and HB540 has been referred to the House State Affairs Committee and is currently being scheduled for public hearings.

BakerHostetler will continue to monitor the progress of these three bills during the remainder of the Texas Legislature’s 84th Session.

]]>http://www.northamericashaleblog.com/2015/03/12/texas-legislature-takes-further-aim-at-localmunicipal-fracking-bans/feed/0http://www.northamericashaleblog.com/2015/03/12/texas-legislature-takes-further-aim-at-localmunicipal-fracking-bans/Is a Statewide Ban in Colorado in Play for 2016?http://feeds.lexblog.com/~r/northamericashaleblog/~3/3UalUZOypr4/
http://www.northamericashaleblog.com/2015/03/02/is-a-statewide-ban-in-colorado-in-play-for-2016/#commentsMon, 02 Mar 2015 15:30:08 +0000http://www.northamericashaleblog.com/?p=2798Continue Reading]]>While Colorado cities continue to litigate their authority to ban fracing, a new environmental group is rallying to ban the practice throughout the entire state. At a gathering on February 24, the “Coloradans Against Fracking” announced that “[w]e need to have a ban in this state.”

The group’s spokesperson, Karen Dike, first announced that the group would pursue a 2016 ballot measure banning the practice. But she backtracked on Wednesday, clarifying that they would press Colorado Governor John Hickenlooper to issue an executive order banning the practice before it resorted to a ballot measure.

Dike urged the governor to “do the right thing and protect Colorado citizens, but if he doesn’t, we’ll look at other ways to achieve our goal, and our goal is to ban fracking in the state of Colorado.” But it’s unlikely that the governor will comply.

On Thursday, he allayed any fears of an executive order. He explained, “We can’t find examples in Colorado, or more than one or two examples, where fracing has caused harm or been sufficiently dangerous to the public that would justify us to ban it.” He expressed fear that a ban would “threaten a $20 billion-a-year industry that provides 100,000 jobs in the state.”

This is not the first time the state has considered a ballot proposal banning fracing (see here and here). In 2013, two measures came close to making it on to the ballot – one so severely restricting the practice that many viewed it as an effective ban. Both measures were pulled at the last minute after the governor agreed to create a task force regulating the industry.

]]>http://www.northamericashaleblog.com/2015/03/02/is-a-statewide-ban-in-colorado-in-play-for-2016/feed/0http://www.northamericashaleblog.com/2015/03/02/is-a-statewide-ban-in-colorado-in-play-for-2016/Pennsylvania Governor Proposes Severance Taxhttp://feeds.lexblog.com/~r/northamericashaleblog/~3/Rd6GZRJ8I9U/
http://www.northamericashaleblog.com/2015/02/25/pennsylvania-governor-proposes-severance-tax/#commentsWed, 25 Feb 2015 15:00:39 +0000http://www.northamericashaleblog.com/?p=2795Continue Reading]]>Pennsylvania Governor Tom Wolf has proposed a new state severance tax on natural gas drilling. The measure, which the governor introduced as a means to fund the state’s education system, would impose a 5 percent tax on the value of gas withdrawn from within the Commonwealth, plus a volume extraction tax of 4.7 percent per 1,000 cubic feet of natural gas. The severance tax would replace the state’s current impact fee, which imposes a charge on oil and gas developers for each new well drilled in Pennsylvania and funnels revenue back to the communities where the drilling takes place.

According to the governor, the severance tax could generate upwards of $1 billion annually. But he said he has yet to “work out a formula” concerning how revenue will be split among local governments and the education system. If approved by the legislature, the tax would take effect at the beginning of 2016, providing revenue for the state in the 2017 fiscal year.

The proposal is not the first time a severance tax has been introduced by state officials. Both Democratic and Republican lawmakers have voiced support for such a measure within the past few years. Democratic State Senator James R. Brewster argued that the revenues generated by Governor Wolf’s plan could “help relieve pressure on the local property tax and save local taxpayer dollars.”

But strong opposition to the measure has also already developed. Gene Barr, President and CEO of the Pennsylvania Chamber of Business and Industry, an organization that advocates for private-sector interests, framed the governor’s plan as a potential hindrance to economic growth in the Commonwealth: “Placing additional tax burdens on natural gas drillers won’t only drive them to other states that share our natural resources. It will lead to a decline in the ancillary and supply chain jobs that are helping our middle class thrive, which will cause us to lose our competitive advantage in the shale play.”

Pennsylvania’s natural gas industry is in the midst of an unprecedented boom. According to the U.S. Energy Information Administration, the Commonwealth is the fastest-growing natural-gas-producing state in the country, a trend fueled by its vast reserves in the Marcellus and Utica Shale plays. Pennsylvania is also the only major energy-producing state in the country that does not currently impose a severance tax on drillers.

We will provide updates as this story develops. Click here and here for additional coverage.

]]>http://www.northamericashaleblog.com/2015/02/25/pennsylvania-governor-proposes-severance-tax/feed/0http://www.northamericashaleblog.com/2015/02/25/pennsylvania-governor-proposes-severance-tax/OPEC’s Price War Is Entrenching North American Shale Producers’ Global Competitive Advantagehttp://feeds.lexblog.com/~r/northamericashaleblog/~3/6a-laZlm-KA/
http://www.northamericashaleblog.com/2015/02/24/opecs-price-war-is-entrenching-north-american-shale-producers-global-competitive-advantage/#commentsTue, 24 Feb 2015 15:00:02 +0000http://www.northamericashaleblog.com/?p=2792Continue Reading]]>Oil price uncertainty strengthens the global competitive advantages of U.S.—and Canadian—unconventional oil projects. Both countries offer excellent geology, robust supporting infrastructure, deep local capital markets, stable politics, and favorable legal and regulatory regimes. They will be the markets that see the leading edge of efficiency improvements and cost decreases. In a nutshell, the OPEC low-cost producers’ decision to launch and sustain a crude oil price war will only entrench and increase the North American shale drillers’ first-mover advantage over the next several years.[1]

The U.S. already has a massive lead on other countries that are developing (Argentina) or that seek to develop (China, Mexico, Russia) unconventional oil and liquids projects, as reflected by the fact that liquids output growth in the U.S. between 2009 and 2014 was roughly three times larger than that of Canada, China, and Russia combined (Exhibit 1).

Exhibit 1: U.S. Liquids Production Growth Compared to That of Other Current and Potential Unconventional Oil Producer Countries

Source: EIA, El Universal, National Energy Board, NBS China, Reuters

First-mover status favors the core U.S. and Canadian developments because most overseas shale oil projects (in China, for instance) are in the test phase and remain too small to capture economies of scale and thus need much higher oil prices to produce economically. Even for the main non-North American play that is actually in commercial development—Argentina’s Vaca Muerta—analysts estimate that it needs prices close to $85 per barrel to break even.[2] This is on par with the highest-cost U.S. plays such as the Tuscaloosa Marine Shale—and far above the costs of the Bakken, Eagle Ford, and Permian, which have many areas that are profitable at prices as low as $50/bbl (and in some cases lower).[3] And these breakeven points in the U.S. are likely to fall as costs decline—indeed, one of the largest U.S. unconventional oil producers expects its drilling and completion costs to decline by at least 20 percent in 2015.[4]

E&Ps are likely to slow or defer development plans for unconventional oil and liquids projects in Argentina, Mexico, Russia, and China—particularly if prices remain weak another three to six months, which looks likely. Slowing or deferring these projects will significantly retard the pace of their development, as many of the specific completion procedures needed to “crack the code” and efficiently and successfully develop unconventional liquids projects are typically locally generated and play-specific.

Optimizing well and completion designs requires experimentation, involves trial and error, and can take years in a new play—even in the freewheeling, innovative U.S. oil patch. It also requires lots of drilling—the simple shale arithmetic is that more wells drilled equals more data to study and more opportunities to learn and improve. A prolonged period of low prices risks stalling this process, particularly outside North America.

Just because U.S. producers are mastering the shale game does not mean their experiences will be neatly transferrable to foreign projects. Indeed, China’s shale gas and oil development to date has thus far significantly underperformed relative to expectations despite China’s multibillion-dollar investments in U.S. projects, hiring service companies with deep experience in U.S. shale gas, and researching the U.S. shale revolution.[5]

Herein lies the irony of OPEC’s actions: most North American shale producers are no longer the marginal, high-cost global barrels. Low prices are simply making the strong stronger—EOG Resources reports it now makes better returns on oil at $65 per barrel than it did at $95 per barrel in 2012.[6] Plus, in the unconventional plays in the United States that primarily produce natural gas (such as the Marcellus), infrastructure improvements, pending LNG exports, and healthy industrial demand will continue to support robust natural gas drilling and production activity.

Whatever challenges U.S. unconventional producers face in the current environment, aspiring shale developers in other locations face much larger challenges. The realities explained above beg the question of what the Saudis and other low-cost OPEC producers’ true objective is—do they really seek simply to punish North American shale drillers, or are they instead playing a longer game and seeking to sidetrack the potential emergence of a global shale boom that could trigger a long-lived oil price collapse?

[1] By “low-cost producers,” the author refers to Saudi Arabia, Iraq, Kuwait, Qatar, and the UAE, which have the lowest production costs in OPEC and are best positioned to weather low prices for several more quarters if necessary as they compete for market share.

[3] Cimarex Energy, “Corporate Update—February 2015,” showing that Wolfcamp wells in the Delaware Basin can now make internal rates of return between 33 percent and 52 percent with oil at $40/bbl; http://cimarex.investorroom.com/presentations (accessed on Feb.19, 2015).

]]>http://www.northamericashaleblog.com/2015/02/24/opecs-price-war-is-entrenching-north-american-shale-producers-global-competitive-advantage/feed/0http://www.northamericashaleblog.com/2015/02/24/opecs-price-war-is-entrenching-north-american-shale-producers-global-competitive-advantage/State Oil and Gas Laws v. Local Control: The Struggle Continues in Ohiohttp://feeds.lexblog.com/~r/northamericashaleblog/~3/gHeQgRe0qrI/
http://www.northamericashaleblog.com/2015/02/23/state-oil-and-gas-laws-v-local-control-the-struggle-continues-in-ohio/#commentsMon, 23 Feb 2015 16:28:26 +0000http://www.northamericashaleblog.com/?p=2789Continue Reading]]>On February 17, 2015, the Ohio Supreme Court announced its ruling in The State Ex Rel. Morrison v. Beck Energy Corporation et al. That closely-watched case addressed whether local ordinances that impact drilling operations are preempted by the Ohio Department of Natural Resources’ (ODNR’s) authority to issue oil and gas drilling permits under R.C. Chapter 1509. In this case, Beck Energy had received a permit from ODNR to drill for oil and gas in the city of Munroe Falls. As Beck Energy began its operations, Munroe Falls successfully sought an injunction from an Ohio state court based on Beck Energy’s non-compliance with several local ordinances, including requirements to obtain a “zoning certificate,” pay a specified fee, and secure a performance bond. The court of appeals reversed the trial court, holding that Ohio’s Home Rule Amendment did not allow the city to impose its own permit requirements on oil and gas drilling operations.

In a clear victory for Beck Energy, a divided Ohio Supreme Court agreed with the appeals court ruling and invalidated all five local ordinances. A close reading of the multiple opinions, however, shows that the court did not categorically preempt all forms of local regulation that impact drilling operations. Rather, it left the door open for further litigation regarding whether “local land use ordinances that address only the traditional concerns of zoning laws, such as ensuring compatibility with local neighborhoods, preserving property values, or effectuating a municipality’s long-term plan for development, by limiting oil and gas wells to certain zoning districts” are enforceable. In other words, the court invalidated what it considered to be a “separate permitting regime” at the local level, but declined to rule on whether more traditional exercises of local zoning that impact drilling operations are enforceable.

While the court ultimately struck down each of the local ordinances by a vote of four to three, the court’s seven justices issued a total of five opinions: a primary opinion, a concurring opinion, and three dissents. The primary opinion, signed by three justices, applied a three-part test for determining whether the city’s ordinances “represent a valid exercise of its home-rule power” or whether they “exercise their police powers in a manner that conflicts with general laws.” The primary opinion concluded:

(1) the ordinances constituted an exercise of the police power rather than local self-government, because they do not “regulate the form and structure of local government” but instead prohibited “the act of drilling for oil and gas without a municipal permit”;

(2) R.C. 1509, which gave the ODNR its authority to issue the drilling permits, was a generally applicable law; and

(3) the ordinances did conflict with the state statute because they “prohibit what [the statute] allows” by creating additional requirements that must be satisfied before a company can commence drilling operations.

As a result, the court invalided each of the ordinances. Notably, however, the primary opinion explicitly limited its “holding … to the five municipal ordinances at issue in this case” and made “no judgment as to whether other ordinances could coexist with the General Assembly’s comprehensive regulatory scheme.”

The concurring opinion, which was signed by two justices (Justice Sharon L. Kennedy signed both the primary and concurring opinions) and was necessary for the judgment to attain a majority, provides additional clarity regarding which types of ordinances are not prohibited by the majority opinion. In relevant part, the concurring opinion states that it agrees “with the determination that this statute preempts local permitting ordinances applicable to the construction and operation of oil and gas wells within the municipality” and must therefore be struck down. The concurring opinion stresses, however, that it is not answering whether “local land use ordinances that address only the traditional concerns of zoning laws” and do not “impos[e] a separate permitting regime applicable only to oil and gas drilling” are untenable or whether the “General Assembly intended to wholly supplant all local zoning ordinances.” Instead, the main purpose of the concurring opinion appears to be to bolster the position that local zoning ordinances should be afforded significant respect and construed, if possible, to be given effect alongside state drilling statutes.

When read together with the three dissents, the concurring opinion provides some insight as to how the court may ultimately decide future drilling-preemption cases concerning legitimate zoning regulation. First, the opinion goes out of its way to state that a municipality’s authority to enact zoning ordinances flows from both the Ohio Constitution and statute and, under the case law, courts are “obliged to accord a strong presumption in favor of the validity of [a zoning] ordinance.” Next, the concurring opinion asserts that while the legislature granted ODNR the “sole and exclusive authority to regulate the location and spacing of oil and gas wells,” the terms “location” and “spacing” have “specialized, technical meanings in oil and gas law” relating to “the placement of wells on a tract in relation to the resource pool and to each other.” It follows, according to the concurring opinion, that it is the state that has the scientific expertise to make judgments related to these safety and efficiency considerations, but “that same scientific and regulatory expertise is not required to determine whether an oil and gas well is compatible with the character and aesthetics of a particular zoning district, such as a residential neighborhood, and we generally presume that zoning authorities are far more familiar with local conditions and therefore are better able to make land use decisions.” This view, to which two justices subscribe in the concurring opinion, lines up with that of the three dissenting justices, who want to “leave[] room for municipalities to employ zoning regulations that do not conflict with the statute” because “the state and the local authority have differing interests in this important matter.” Lastly, both the concurring opinion and the principal dissent note that New York, Pennsylvania, and Colorado are all home-rule states whose courts have held that certain local zoning ordinances that do not attempt to regulate actual drilling operations can and should survive alongside state drilling statutes as legitimate exercises of local control. From the Ex Rel. Morrison opinions, it appears that five of the seven Ohio Supreme Court justices agree.

Although oil-and-gas drilling in Ohio may be slowing down due to current oil, gas, and natural gas prices, conflicts concerning whether drilling companies must comply with all local ordinances and regulations will certainly continue. The Ohio Supreme Court spoke clearly that local regulations that create additional permitting requirements or “discriminate against, unfairly impede, or obstruct oil and gas activities and production operations that the state has permitted” are preempted and unenforceable. While the justices gave clues regarding how they will likely approach legitimate local zoning regulations that have an incidental impact on drilling operations, their future rulings will necessarily be influenced by the scope of those zoning regulations and whether those regulations attempt to broadly restrict all drilling activity within a municipality. In that respect, Ex Rel. Morrison is just the beginning of the court’s jurisprudence regarding local authority to regulate drilling activities, not the end.

]]>http://www.northamericashaleblog.com/2015/02/23/state-oil-and-gas-laws-v-local-control-the-struggle-continues-in-ohio/feed/0http://www.northamericashaleblog.com/2015/02/23/state-oil-and-gas-laws-v-local-control-the-struggle-continues-in-ohio/New Mexico Federal Court Frames The Issues That Will Define Future Fights Over Local Fracking Regulationhttp://feeds.lexblog.com/~r/northamericashaleblog/~3/RdMn8CT3JMY/
http://www.northamericashaleblog.com/2015/02/19/new-mexico-federal-court-frames-the-issues-that-will-define-future-fights-over-local-fracking-regulation/#commentsThu, 19 Feb 2015 15:00:14 +0000http://www.northamericashaleblog.com/?p=2786Continue Reading]]>On January 15, 2015, the United States District Court for the District of New Mexico became the first federal court to address questions related to the scope of local governments’ ability to regulate oil and gas development within those governments’ jurisdictional boundaries. In SWEPI, LP v. Mora County, New Mexico, the district court struck down a county ordinance prohibiting the extraction of oil and gas, a decision that has generally been hailed as a victory for industry. Yet a closer reading of the 199-page opinion that United States District Judge James O. Browning issued reveals that the real import of the SWEPI decision is not the result, but the framework the court articulated for analyzing two issues driving the public debate over the regulation of oil and gas development: whether state and federal laws permitting oil and gas extraction preempt local regulation of oil and gas operations, and whether, if local regulation is permissible, those regulations can represent a taking of private property.

In SWEPI, the federal district court concluded that, while there may be limitations on local communities’ ability to regulate oil and gas operations, at least in New Mexico those limitations are not likely to foreclose local governments from regulating entirely. And while not deciding the issue, Judge Browning became the first federal judge to meaningfully grapple with the question regarding whether local regulation of oil and gas, and specifically regulation of hydraulic fracturing, has the potential to result in an uncompensated taking of a mineral interest in violation of the Fifth Amendment to the United States Constitution. Given the court’s comprehensive treatment of the pertinent legal issues relevant to those questions, the opinion in SWEPI is likely to be influential in shaping the approach of both regulators and industry in the future.

I. BACKGROUND

Beginning in 2010, Royal Dutch Shell subsidiary, SWEPI, LP (“SWEPI”), acquired a series of oil and gas leases in Mora County, New Mexico. Mora Country is a sparsely populated rural county in northeastern New Mexico. There was no oil and gas production activity in Mora County at the time that SWEPI obtained its interest in the leases, and none has occurred in the county since.

Notwithstanding this lack of development activity, on April 29, 2013, the Mora County Board of County Commissioners enacted an ordinance entitled “Mora County Community Water Rights and Local Self-Government Ordinance.” The ordinance purports to make it “unlawful for any corporation to engage in the extraction of oil, natural gas, or other hydrocarbons within Mora County.” The ordinance also provides that other sources of law that could be interpreted to grant a right to develop oil and gas – including federal and state statutory and constitutional law – would not be effective in the county and would have no preemptive effect on the ordinance.

On January 10, 2014, SWEPI brought suit against the county raising a number of challenges to the ordinance’s validity under federal and state law. Echoing contentions raised in lawsuits opposing local restrictions on hydraulic fracturing pending presently in state courts across the country, SWEPI contended that federal and state laws regulating the development of oil and gas interests preempted the local ban. Because Mora County’s ordinance only precluded corporations, and not individuals, from developing oil and gas, SWEPI also argued that Mora County’s ordinance denied corporations equal protection under the law. And because the ordinance denied mineral owners the ability to develop and sell oil and gas, SWEPI argued that, even if Mora County’s ordinance was enforceable, the county’s action represented an uncompensated taking of a property interest.

II. SOME ANSWERS, MORE QUESTIONS

In an exhaustive opinion granting judgment in SWEPI’s favor, the federal district court had little trouble rejecting Mora County’s attempt to elevate the county ordinance above the limitations that the federal Supremacy Clause imposes on local lawmaking. Judge Browning explained that “Mora County lacks the authority to nullify constitutional rights” and observed that “[i]f a county could declare under what conditions federal law preempted its law, federal law would not be preemptive at all.” With reference to the county’s attempt to restrict the fundamental rights of corporations specifically, the court emphasized that Supreme Court precedent recognizing corporate rights was controlling and concluded that the “local law is contrary to over [100] years of Supreme Court precedent.” Judge Browning noted: “[Mora County’s] argument that corporations should not be granted constitutional rights, or that corporate rights should be subservient to people’s rights, are arguments that are best made before the Supreme Court – the only court that can overrule Supreme Court precedent – rather than a district court.”

The district court also determined that the ordinance likewise “strays from the historical territory of county lawmaking,” stating that “[r]egulating oil-and-gas production is not within the purview of traditional county powers” and acknowledging that, “[i]n New Mexico, oil-and-gas regulations have traditionally been left to the state and to the Oil and Gas Commission.” Observing that the New Mexico Oil & Gas Act provides “the Oil Conservation Division with a number of powers concerning the regulation of drilling for, and producing oil and gas,” Judge Browning concluded that “the Oil and Gas Act impliedly preempts [Mora County] from completely banning oil-and-gas production.”

In the weeks since the decision, this has been the holding that industry commentators have cheered. What has been overlooked, however, is that the court’s decision went no further. Judge Browning did not hold that local governments have no place in the regulation of oil and gas development. To the contrary, he was express in adopting the opposite view. Noting that the Oil and Gas Act omitted regulation of pertinent aspects attendant to development such as the “traffic that oil-and-gas production creates,” “noise limitations for production near residential areas,” “potential nuisance issues from sound, dust, or chemical run-off,” and “the impact of oil-and-gas production on neighboring properties” the court reasoned that New Mexico law “does not preempt the entire oil-and-gas field.” Rather than eliminate Mora County’s ability to regulate oil and gas activity, Judge Browning’s opinion affords “room for concurrent regulation.”

This “room” all but assures that local governments embracing Mora County’s opposition to oil and gas development will attempt more nuanced efforts to restrict operations through use of regulations focused on the aspects of development that Judge Browning referenced in the SWEPI opinion, as well as other activity attendant to development, but not expressly addressed in the New Mexico Oil & Gas Act. Whether these nuances will manifest in a form that will permit local enforcement, or whether future efforts will represent the functional equivalent of bans on extraction (and therefore be equally unenforceable) will depend on the letter and the application of subsequent regulatory efforts. Suffice to say, the result in SWEPI does little to settle the debate on the scope of local control over oil and gas development in New Mexico or elsewhere.

And even if local governments are successful in exerting regulatory power that restricts or eliminates the ability to develop oil and gas within the local government’s jurisdictional boundary, there still remains the question of whether mineral owners may have constitutional recourse for the frustration of these property rights. Although the court in SWEPI did not decide whether Mora County’s ordinance constituted an uncompensated taking – because SWEPI’s failure to seek just compensation under state processes rendered SWEPI’s takings claim unripe – the district court did conclude that because the ordinance “effectively destroys all economic value that SWEPI, LP has in its leases,” SWEPI had alleged an injury-in-fact, endowing SWEPI with standing to bring a takings claim. Judge Browning explained that because the value in SWEPI’s oil and gas leases derived from the right to drill for oil, without the right to drill, “an oil and gas lease is worthless.”

Given Judge Browning’s acknowledgment that the Mora County ban on hydrocarbon extraction represents “a particularized, concrete interest in property that state law protects,” it is not a substantial leap to conclude that the court would be open to declaring broad extraction bans like the one Mora County enacted uncompensated takings of mineral interests. But similar to the court’s holding on preemption, the court’s takings analysis suggests that more nuanced regulatory efforts might be able to withstand constitutional scrutiny. The court’s opinion does not address whether a ban on oil and gas development would represent a taking when the mineral owner is also the fee owner of the surface estate. And in response to the court’s probing at oral argument, SWEPI’s counsel conceded that, if Mora County had banned only hydraulic fracturing, as opposed to a total ban on extraction, the takings implications would be less certain.

III. CONCLUSION

Although Judge Browning’s thoughtful opinion in SWEPI v. Mora County certainly advances the legal thinking on questions of local control and constitutional protection of mineral rights, it does not provide any conclusive answers to the two questions that continue to dominate the policy debate over how best to regulate domestic oil and gas production. Nor is it likely that a universal answer will present itself soon. States like New Mexico and Colorado – where court decisions have favored state preemption – are presently treading a path on these questions distinct from jurisdictions like New York and Pennsylvania – where court decisions have empowered local governments. How these questions affect the business approach of operators and the political strategy of regulators may drive the fate of the domestic oil and gas industry in 2015 and beyond.

]]>http://www.northamericashaleblog.com/2015/02/19/new-mexico-federal-court-frames-the-issues-that-will-define-future-fights-over-local-fracking-regulation/feed/2http://www.northamericashaleblog.com/2015/02/19/new-mexico-federal-court-frames-the-issues-that-will-define-future-fights-over-local-fracking-regulation/Crude-by-Rail Update: What to Expect From Recent Crude Oil Derailmentshttp://feeds.lexblog.com/~r/northamericashaleblog/~3/vvf-rPuO0PM/
http://www.northamericashaleblog.com/2015/02/18/crude-by-rail-update-what-to-expect-from-recent-crude-oil-derailments/#commentsWed, 18 Feb 2015 13:59:20 +0000http://www.northamericashaleblog.com/?p=2784Continue Reading]]>These are uncertain and stressful times for all involved in the transportation of crude oil by rail. Since February 14, two fiery derailments in West Virginia and Ontario have refocused an unwelcome spotlight on the necessity of transporting crude oil production by railroad in areas without adequate access to pipelines.

The attention comes at a politically sensitive juncture as the Pipeline and Hazardous Materials Safety Administration’s and the Federal Railroad Administration’s comprehensive crude-by-rail safety rule awaits review with the White House’s Office of Management and Budget[1] – a process that will likely produce a final rule by mid-May.

But can companies involved in crude-by-rail expect other repercussions from the two recent derailments? Without a doubt they can.

Unsurprisingly, environmental group opposition will increase as the recent disasters are prophesized as harbingers of disasters to come.[2] Indeed, photos of the derailment in West Virginia show the fire burning on the banks of the Kanawha River, which will increase resistance to crude oil traveling in close proximity to environmentally sensitive water sources.[3]

[4]

Grassroots resistance to any crude-oil trains traveling through citizens’ backyards will increase as well. Although this resistance has already been fierce in some states, opposition in states that are geographically remote from current crude oil production may continue to grow. In turn, citizens will pressure their state and federal political representatives for tighter restrictions on crude-by-rail.[5] Grassroots resistance may grow quickly due to striking headlines created by the evacuation of 2,500 people and the declaration of a state of emergency in West Virginia.[6]

As the political opposition increases, PHMSA and FRA will face additional pressure to adopt more stringent safety standards in the final crude-by-rail rule. The recent events may lend some support to that pressure, as the train that derailed in West Virginia consisted entirely of CPC-1232 tank cars[7] – a tank car with more stringent design standards than the controversial DOT-111s. As the crude-by-rail rule is currently written, the agencies propose a slightly improved CPC-1232 as the least-stringent design standard for new tank cars.[8] The West Virginia derailment will likely increase pressure on the agencies not to select the CPC-1232-based option for new tank cars, which would in turn likely lead to more expensive and more onerous requirements for the construction of the new DOT-117 tank car.[9]

Finally, the Department of Transportation, through PHMSA or FRA, could exercise its emergency order powers to immediately address perceived safety risks[10] – as DOT has done to respond to crude-by-rail accidents since the Lac-Mégantic, Canada, derailment. A potential emergency order could mandate immediately implementable operational requirements such as speed limits or routing restrictions for crude-by-rail. Or a potential emergency order could reach further and impose limitations on the types of equipment that may be used in crude-oil unit trains, such as tank car types or braking systems. Action of this type may reveal an early glimpse of the requirements that the final crude-by-rail rule will impose.

Whatever transpires from the two recent derailments, it is certain that the crude-by-rail industry will continue to face vociferous opposition and unsettling uncertainty until – and likely after – PHMSA and FRA finalize the proposed crude-by-rail rule.

[10] 49 U.S.C. §§ 5121, 20104(a)(1) (providing for emergency order power under the Hazardous Materials Transportation Act and the Federal Railroad Safety Act).

]]>http://www.northamericashaleblog.com/2015/02/18/crude-by-rail-update-what-to-expect-from-recent-crude-oil-derailments/feed/0http://www.northamericashaleblog.com/2015/02/18/crude-by-rail-update-what-to-expect-from-recent-crude-oil-derailments/China to Increase Shale Gas Productionhttp://feeds.lexblog.com/~r/northamericashaleblog/~3/S8jbcEq7-aA/
http://www.northamericashaleblog.com/2015/02/17/china-to-increase-shale-gas-production/#commentsTue, 17 Feb 2015 17:08:55 +0000http://www.northamericashaleblog.com/?p=2783Continue Reading]]>China plans to increase its shale gas production from 1.3 billion cubic meters of shale gas per year to 30 billion cubic meters per year by 2020, according to Chen Weidong of China National Offshore Oil Corp. This goal is significantly less than the 60 to 80 billion cubic meter goal set in 2012, when the Chinese government declared it would start extracting its reserves, which are the largest in the world. The goal was reduced because of difficult drilling conditions.

Though China became the second largest shale gas producer in 2014, it will likely have to increase its reliance on imports over the next few years because demand is growing faster than production. “Last year, the import dependency was about 31 percent. By 2020 that dependency will go up to 40 to 50 percent,” said James Henderson, senior research fellow at the Oxford Institute for Energy. “We’ll get the supply from Russia and also [from] Turkmenistan. We’ve already got secured supplies for over 400 billion cubic meters for 2020.” Turkmenistan supplies nearly half of China’s gas imports.

As part of its efforts to increase production, China drilled 200 new wells in 2014, bringing its total to 400. According to Chen, China will add “a few hundred a year for sure. No problem.” However, it may not be as simple as drilling more wells. “China has the biggest potential,” Henderson said. “But it’s one thing to have the gas [and] another thing [to contend with] rocks, fractions, and reservoirs [that affect] access to water. China has a massive water shortage.” Drilling and hydraulic fracturing use a lot of water, and most of China’s shale gas reserves are located in arid parts of the country.

Despite these and other impediments, China continues to pursue an increase in shale gas production to not only reduce its reliance on coal, which accounts for nearly 70 percent of its energy consumption, but also to combat unhealthy levels of pollution. The capital of Beijing is often under smog alerts and many people have taken to wearing masks. There is even a Twitter account called BeijingAir that tweets updates several times a day on the smog levels. On Friday, February 13, it was “hazardous.”

High levels of pollution in Beijing have led to serious health problems. “Over the past 10 years, lung cancer in Beijing has increased 45 percent. So everybody knows that the first challenge for energy is a sustainability issue,” Chen said. “We have the ‘Beijing cold.’ People go to the hospital, but medicine is no use, so they leave Beijing and stay for a few months outside [the city] to get better. That’s the Beijing cold.”

For more information on shale gas production in China, click here, here, and here.

]]>http://www.northamericashaleblog.com/2015/02/17/china-to-increase-shale-gas-production/feed/0http://www.northamericashaleblog.com/2015/02/17/china-to-increase-shale-gas-production/When Oil Prices Head South, So Do the Bakken Oil Trainshttp://feeds.lexblog.com/~r/northamericashaleblog/~3/EW8vmookTmw/
http://www.northamericashaleblog.com/2015/02/11/when-oil-prices-head-south-so-do-the-bakken-oil-trains/#commentsWed, 11 Feb 2015 20:31:41 +0000http://www.northamericashaleblog.com/?p=2771Continue Reading]]>Bakken crude oil increasingly heads south as low oil prices erode its competitive advantage in the U.S. East Coast market. The price of WTI crude oil—the benchmark price for most U.S. shale crudes—is moving toward parity with Brent, the international crude price benchmark for grades such as Nigerian Bonny Light that compete with Bakken in the U.S. East Coast market. This reduces the economic incentive for refiners to bring Bakken oil nearly 1,800 miles by rail when they can procure seaborne cargoes of light, sweet crude oil from Nigeria, Angola, and other niche suppliers such as Azerbaijan, which eagerly seek buyers because the U.S. shale revolution largely displaced them from the massive U.S. crude market.In essence, when WTI’s discount to Brent falls below $5/bbl, East Coast refiners’ incentive to bring in Bakken crude by rail declines because the economics come to favor imported crudes.

For the past five months, WTI’s discount to Brent has been at or below $5/bbl. Accordingly, rail movements of crude from the Bakken to the East Coast appear to be slowing down. As early as November 2014, rail watchers in the Albany, NY area, a key hub for Bakken crude oil trains, noticed that traffic had dropped significantly.[1] In January 2015, market intelligence firm Genscape recorded multiple crude oil trains arriving at the Cushing, OK, area for the first time in at least two months. [2] While the precise movements of Bakken crude around the U.S. rail system are opaque, the Cushing storage area has seen its weekly crude inventories rise consistently for 13 weeks, beginning in late October 2014, which strongly suggests Bakken barrels are heading south to a much greater extent than before (Exhibit 1).

Petroleum rail carload data support the thesis that crude volumes leaving the Bakken by rail may have declined slightly as pipelines such as Kinder Morgan’s Double H project start up, but more important, rail volumes remain sizeable and are heading south rather than east. According to the American Association of Railroads, U.S. railways moved 15,503 carloads of petroleum and petroleum products in the last week of January 2015, a year-on-year increase of 17%. Yet railcar brokers now report a surplus of oil tank cars, and monthly lease rates have plummeted from $2,450 in January 2014 to only about $1,300 in January 2015—a nearly 50% decline.[3]

The fact that more cars are moving but prices per car have fallen so rapidly suggests that the distance those cars are traveling is very likely substantially shorter than it was when wide price spreads between Bakken and imported crude oil justified the long and costly rail journey from North Dakota to the U.S. East Coast. To underline the lost railcar utilization caused by Bakken crude trains moving to Cushing instead of East Coast refineries, note that the distance from EOG Resources’s rail loading terminal at Stanley, ND, to Cushing is approximately 1,100 miles, while Stanley to Philadelphia (a key East Coast Bakken crude demand point) is approximately 1,750 miles.[4] Thus, the journey to Cushing requires approximately 37% less railcar usage compared to moving the same volume of crude from North Dakota into the Philadelphia area.

Ultimately, the market for crude by rail transportation is similar to that for crude oil itself. Relatively small changes in demand can spark outsized price movements. Unfortunately for Bakken crude producers at the moment, their geographic isolation and relative lack of access to pipelines compared to producers in the Eagle Ford, Niobrara, and Permian mean Bakken crude will continue to sell at a heavier discount. This was bearable when prices exceeded $100/bbl, but as long as prices stay below $60/bbl, Bakken’s transportation-induced pricing disadvantage will likely accelerate rig count declines relative to those of other basins.

[4] This is a simple Google Maps measurement. Due to curves and topography, the actual rail distance may be somewhat longer, but the fundamental difference between the Stanley-to-Cushing and Stanley-to-Philadelphia route distances endures.

]]>http://www.northamericashaleblog.com/2015/02/11/when-oil-prices-head-south-so-do-the-bakken-oil-trains/feed/0http://www.northamericashaleblog.com/2015/02/11/when-oil-prices-head-south-so-do-the-bakken-oil-trains/U.S. Geological Survey Releases Publications on Historical Hydraulic Fracturing Trendshttp://feeds.lexblog.com/~r/northamericashaleblog/~3/e3n1sATGsu4/
http://www.northamericashaleblog.com/2015/02/03/u-s-geological-survey-releases-publications-on-historical-hydraulic-fracturing-trends/#commentsTue, 03 Feb 2015 21:40:24 +0000http://www.northamericashaleblog.com/?p=2769Continue Reading]]>On Tuesday, January 27, the U.S. Geological Survey released two new publications highlighting historical hydraulic fracturing trends. These publications are the first of their kind: until now, there has not been comprehensive, published, publicly available information regarding the extent, location, and character of hydraulic fracturing in the United States.

The report is an analysis of data on nearly one million hydraulically fractured wells and 1.8 million fracturing treatment records from 1947 through 2010. While the report is a nationwide study of hydraulic fracturing trends, the bulk of the analysis focuses on Texas, which has historically had the highest number of records of hydraulic fracturing treatments and associated wells.

The data series consists of datasets in 21 spreadsheets that outline the geographical distributions of hydraulic fracturing treatments and associated wells (including well drill-hole directions) as well as water volumes, proppants, treatment fluids, and additives used in hydraulic fracturing treatments in the United States. It also describes the data–extraction/aggregation processing steps, field names and descriptions, field types, and sources.

The scientific investigation report uses the data to identify hydraulic fracturing trends in drilling methods and use of proppants, treatment fluids, additives, and water in the United States. The trends are compared with those in peer-reviewed literature to establish a common understanding of the differences in hydraulic fracturing and provide a context for understanding the costs and benefits of increased oil and gas production. The publications also examine how newer technology has affected the amount of water needed for hydraulic fracturing and where hydraulic fracturing has occurred at different points in time.

The publications fill a gap in the historical and scientific literature surrounding hydraulic fracturing in the United States, and will be a valuable tool in the changing regulatory climate of hydraulic fracturing.

The report, “Trends in Hydraulic Fracturing Distributions and Treatment Fluids, Additives, Proppants, and Water Volumes Applied to Wells Drilled in the United States from 1947 through 2010—Data Analysis and Comparison to the Literature,” is available here. The data set, “Data Regarding Hydraulic Fracturing Distributions and Treatment Fluids, Additives, Proppants, and Water Volumes Applied to Wells Drilled in the United States from 1947 through 2010,” is available here.

]]>http://www.northamericashaleblog.com/2015/02/03/u-s-geological-survey-releases-publications-on-historical-hydraulic-fracturing-trends/feed/0http://www.northamericashaleblog.com/2015/02/03/u-s-geological-survey-releases-publications-on-historical-hydraulic-fracturing-trends/Pennsylvania Governor Reinstates Ban on Oil and Gas Leasing in State Parks and Forestshttp://feeds.lexblog.com/~r/northamericashaleblog/~3/5iEis08Omf0/
http://www.northamericashaleblog.com/2015/01/30/pennsylvania-governor-reinstates-ban-on-oil-and-gas-leasing-in-state-parks-and-forests/#commentsFri, 30 Jan 2015 20:51:58 +0000http://www.northamericashaleblog.com/?p=2766Continue Reading]]>On Thursday, January 29, 2015, Pennsylvania’s new governor, Tom Wolf, signed Executive Order 2015-03, thereby reinstating a moratorium on new leases for oil and gas development in state parks and forests. Wolf’s moratorium restores a ban instituted by Governor Ed Rendell just prior to his leaving office in 2010. Republican Governor Tom Corbett had lifted Rendell’s moratorium by Executive Order 2014-03 on May 23, 2014.

Wolf, who campaigned heavily on a promise to ban fracking on state lands, insists that he generally supports fracking, but was concerned with “striking the right balance” because “[o]ur state parks and forests are unique assets that should be preserved, protected, and utilized by our residents for recreational purposes.”

Wolf’s moratorium comes on the heels of a Pennsylvania Commonwealth Court decision earlier this month upholding both the government’s right to lease more public lands for drilling and the application of proceeds to programs other than environmental conservation. In the decision, the Commonwealth Court also ruled that the governor’s office is not empowered to override leasing decisions of the Pennsylvania Department of Conservation and Natural Resources (DCNR). The court reasoned that under the Conservation and Natural Resources Act – the 1995 Act that created DCNR – “DCNR has the exclusive statutory authority to determine whether to sell or lease the Commonwealth’s natural resources for oil and natural gas extraction.” The court observed, however, that “[t]his is not to say that the governor, as the chief executive, and the General Assembly are precluded from attempting to influence DCNR’s leasing decisions.” Given the court’s ruling that the DCNR has ultimate control over leasing decisions, it is questionable whether Governor Wolf’s executive order would be legally effective if DCNR decided to enter into additional leases.

Nevertheless, environmental groups have applauded the decision as showing Wolf’s support for strong environmental regulation. Industry groups, such as the Marcellus Shale Coalition, meanwhile, have sharply criticized Wolf’s decision as a “deeply misguided and purely political action to unnecessarily ban the safe and tightly regulated development of natural gas.”

]]>http://www.northamericashaleblog.com/2015/01/30/pennsylvania-governor-reinstates-ban-on-oil-and-gas-leasing-in-state-parks-and-forests/feed/0http://www.northamericashaleblog.com/2015/01/30/pennsylvania-governor-reinstates-ban-on-oil-and-gas-leasing-in-state-parks-and-forests/2015 Texas Legislative Session Includes Twin Bills Concerning Municipal Fracking Banshttp://feeds.lexblog.com/~r/northamericashaleblog/~3/W_l1BE3cJ0I/
http://www.northamericashaleblog.com/2015/01/22/2015-texas-legislative-session-includes-twin-bills-concerning-municipal-fracking-bans/#commentsThu, 22 Jan 2015 17:55:08 +0000http://www.northamericashaleblog.com/?p=2763Continue Reading]]>With the opening of the 84th Session of the Texas Legislature on January 13, 2015, two of the more closely watched bills in the energy arena will be House Bill 539 (HB539) and House Bill 540 (HB540).

HB539, filed on December 17, 2014, by Representative Phil King (R) of Weatherford, relates to “the procedural requirements for the adoption of a municipal regulation, limitation, or prohibition on the production, storage, or transportation of oil or natural gas.” The bill proposes to require any municipality seeking to enact an “oil and gas measure,” which the bill defines as “a municipal ordinance or other municipal measure … to regulate, limit, or prohibit the production, storage, or transportation of oil or gas,” to prepare a Fiscal Note and an Equalized Education Funding Impact Statement.

The Fiscal Note must state the fiscal implications of the potential oil and gas measure for the state and local governments; the probable cost to the state that will result from the measure, including potential lost tax revenue, lost fees, lost royalty income, and diverted state funds; and the amount of money the municipality adopting the measure will be required to annually remit to the state as reimbursement for the cost to the state resulting from the oil and gas measure.

The Equalized Education Funding Impact Statement focuses on the difference in funding between the “anticipated total cost of attendance credits” for a school district covered by the oil and gas measure and the total cost of attendance credits that would result if the school district’s maintenance and operations tax revenue were not reduced due to the oil and gas measure.

HB539 also provides that if a municipality adopts an oil and gas measure, the municipality must reimburse the state for the cost to the state for a five-year period resulting from the measure as determined by the Fiscal Note.

HB540, also filed on December 17, 2014, by Rep. King, concerns “the submission to the attorney general of a measure proposing the enactment or repeal of a municipal ordinance.” HB540 applies only to a municipality whose charter provides for the proposal by petition of a measure to enact a new ordinance or repeal an existing ordinance. The bill provides that before ordering an election on a proposed new ordinance, the municipality must submit the proposed measure to the attorney general. Within 90 days of the municipality’s submission, the attorney general must determine whether any portion of the proposed measure would violate any constitutional, statutory, or regulatory provisions, or whether the proposed measure would cause governmental taking of private property requiring that just compensation be paid to the property owner.

HB540 would prohibit a municipality from holding an election on the proposed measure if the attorney general determined that any portion of the proposed measure would violate the Texas or federal constitution or a state statute or rule or would cause governmental taking of private property.

No action has been taken on either bill thus far, but BakerHostetler will continue to monitor their progress during the 84th Legislative Session.

]]>http://www.northamericashaleblog.com/2015/01/22/2015-texas-legislative-session-includes-twin-bills-concerning-municipal-fracking-bans/feed/0http://www.northamericashaleblog.com/2015/01/22/2015-texas-legislative-session-includes-twin-bills-concerning-municipal-fracking-bans/Layoffs in the Energy Sector – Are Employers Prepared?http://feeds.lexblog.com/~r/northamericashaleblog/~3/WyGy7JlD8p4/
http://www.northamericashaleblog.com/2015/01/21/layoffs-in-the-energy-sector-are-employers-prepared/#commentsWed, 21 Jan 2015 20:02:57 +0000http://www.northamericashaleblog.com/?p=2760Continue Reading]]>Over the past few weeks, the media has focused intently on the oil and gas industry’s extensive layoffs. Well known energy companies have made front-page news with their announcements of their significant layoffs that have often resulted in the termination of thousands of employees or a significant percentage of their workforce. This trend, it appears, is only beginning, and many employers in the industry or that work closely with the industry will face tough decisions regarding their employees. This is, by and large, common knowledge. As a result, employees, plaintiffs’ attorneys, and government agencies charged with upholding labor and employment law are paying close attention. As companies prepare to conduct future layoffs, they must be vigilant in ensuring that they are complying with federal and state laws and tackling the layoffs in the most efficient and practical way possible. Below are some quick tips for employers to consider as they contemplate and plan actions affecting their workforce.

Employers should ensure that they are aware of any terms contained in employment contracts or policies that must be followed with regard to termination. For example, certain notice or severance obligations may arise under an employment contract or policies and procedures. The employer should also review any continuing contractual obligations applicable to employees subject to layoffs, such as non-competition, non-solicitation, or confidentiality clauses.

If employees in non-United States jurisdictions are subject to the layoff, the employer should carefully review and follow the applicable jurisdictions’ laws related to layoffs. For example, in many foreign jurisdictions, employers must seek government or employee representative (such as a union) approval, must provide notice, must provide severance or termination payments, and must document the terminations in a specific manner. This process takes time and significant effort, so an employer should consider these issues as early as possible.

Analyze whether the layoffs (or future layoffs when considered with current terminations) trigger any notice or disclosure obligations under the federal Worker Adjustment and Retraining Notification Act (WARN Act) or similar state laws. The federal WARN Act applies to companies with more than 100 employees. These notice requirements, which typically require 60 days’ written notice to affected employees and a state labor office, are generally triggered when a certain percentage of employees are subject to a layoff over a period of time (generally 30 or 90 days depending on the circumstances) or an employer closes an entire facility. Liability for failing to provide the notice can be significant, with employees eligible to receive 60 days’ pay (or a portion thereof) for an employer’s failure to provide the notice, and other penalties.

Analyze potential public relations issues. As evidenced by the extensive media coverage, layoffs are news. This news can have an adverse impact on the business and employee morale. Companies, then, must not only consider the legal issues applicable to layoffs, but the press and public relations issues associated with the same.

Consider and analyze the identities of those subject to termination. Does a particular protected category make up a larger percentage of those affected? Has an affected employee recently engaged in protected conduct, such as reporting allegedly unlawful activity? Understanding the makeup of the group chosen for termination helps an employer manage the risk related to the layoff “fall out.”

Consider the legal and practical issues related to the layoffs. When employees are terminated, employers must comply with state laws related to the timing of the final paycheck. Moreover, certain payments, like accrued but unused vacation, may need to be included in the final paycheck. Employers must also consider how the layoffs will be communicated to the employees. Will there be private meetings? A group meeting? Regardless, the employer should always ensure that two or more trusted company representatives are present in the meetings to ensure each representative has a witness. Employers should also consider whether, regardless of contract or policy, any severance payments will be made. If so, employers should engage counsel to assist in preparing severance and release agreements and coordination of the communications to each employee concerning the payments being offered. Many practical components of the layoffs are not considered until it’s too late.

Layoffs are a necessary part of business. After an exciting boom, the oil and gas industry is seeing a retraction that requires employers in the industry to recalibrate and adjust to the business’s current needs. As employers face the prospect of letting go of their employees, they should consider the above-mentioned issues and reach out to legal counsel to ensure that they are conducting their layoffs in a legal, efficient, and practical manner. Failure to do so will result in unnecessary and expensive consequences.

Rep. Bill Johnson (R-OH) subsequently introduced H.R. 351, an identically named bill with virtually identical legislative language, in the House on January 14, 2015.[3] Both bills aim to create an anvil upon which prospective LNG exporters can use the courts to hammer the Department of Energy (DOE) into making faster decisions on project approvals.

At present, U.S. federal regulators have given full and final approval to four LNG projects with a combined export capacity of approximately 7 billion cubic feet per day (BCF/d)—Cheniere Energy’s Sabine Pass facility, Freeport LNG, Cameron LNG, and Carib Energy.[4] Several other projects appear sufficiently advanced that passage of the LNG Permitting Certainty and Transparency Act would accelerate their ability to get shale gas-based LNG into the global marketplace.

The Bill’s Core Provisions

The latest version of the proposed Act would force the Secretary of Energy to make a final decision on any application for authorization to export natural gas under Section 3(a) of the Natural Gas Act within 30 days (versus 45 days for the earlier Barrasso/Heinrich version) of:

(1) the conclusion of the review to site, construct, expand, or operate the liquefied natural gas export facilities required by the National Environmental Policy Act of 1969 (42 U.S.C. 4321 et seq.);

(2) or the date of enactment of this Act, if the NEPA review for a proposed export project has already concluded.[5]

The bill would consider NEPA review “concluded” when the lead agency (typically the Federal Energy Regulatory Commission or FERC):

(1) Publishes a Final Environmental Impact Statement (EIS);

(2) Publishes a Finding of No Significant Impact; or

(3) Determines that an application is eligible for a categorical exclusion pursuant to National Environmental Policy Act of 1969 (42 U.S.C. 4321 et. seq.) implementing regulations.[6]

In a civil suit brought under the Act, if the court found that the Secretary of Energy failed to issue a decision on the application as required under subsection (a), the Court would be required to order the secretary “to issue the decision not later than 30 days after the Court’s order.”[7] Additionally, courts would be required to set civil actions brought under the Act for expedited consideration and would have to set the matter on the docket “as soon as practical after the filing date of the initial pleading.”[8]

The Act’s Practical Impacts

Despite the robust enforcement levers the Act proposes, it would not address a major obstacle to expanding U.S. LNG exports: the ponderous environmental review process for export projects, which can take between 18 and 30 months and cost $100 million for proposals to export LNG to countries with which the U.S. does not have free trade agreements (FTAs).[9]

However, it would force the DOE to make much faster decisions on whether to grant commercially advanced facilities permits allowing them to export gas to countries that do not have free trade agreements with the U.S., a cohort that includes Japan, Ukraine, and other large potential customers for U.S. LNG.

At present, the DOE takes much longer than 30 days to issue final approvals. For instance, Cheniere’s Corpus Christi export facility—which will have the ability to ship 2.1 BCF/d of gas—received its final environmental approval from FERC nearly four months ago but the DOE has still not granted it final approval to export gas to countries that do not have FTAs with the U.S.[10]

Bottom Line: The Act Is a Positive First Step Toward Reducing Regulatory Impediments to Greater U.S. LNG Exports

Industry players recognize that U.S. LNG exporters can capitalize on abundant domestic gas supplies and a large base of pre-existing pipeline and terminal infrastructure to become highly competitive, low-cost global suppliers. Key members of Congress, meanwhile, increasingly view U.S. LNG exports as a form of geopolitical leverage that can help a number of European countries potentially reduce dependence on gas supplies from Russia.[11]

Hammering this point home, Russia is again using natural gas supplies to manipulate Europe. On January 15, 2015, Gazprom announced it plans to shift all Russian gas that currently transits Ukraine to a pipeline through Turkey.[12] If carried through, this will isolate Ukraine and force EU consumer countries to build costly new pipelines connecting Turkey to the EU gas distribution network.

World-class U.S. geology and infrastructure, geopolitical events, and two powerful industry and political interest constituencies are creating a more permissive environment for LNG exports from the U.S. The House and Senate already display healthy bipartisan support for LNG exports, and it is likely that a reasonably strong form of these bills—or at least the objectives they seek to attain—will survive the legislative process and pass in the next few months.

]]>http://www.northamericashaleblog.com/2015/01/16/the-lng-permitting-certainty-and-transparency-act-a-positive-step-toward-expediting-u-s-lng-export-projects/feed/0http://www.northamericashaleblog.com/2015/01/16/the-lng-permitting-certainty-and-transparency-act-a-positive-step-toward-expediting-u-s-lng-export-projects/Crude-by-Rail Update: Municipalities in the Bakken Push Back Against Increasing Train Traffichttp://feeds.lexblog.com/~r/northamericashaleblog/~3/LjMZT9XDxIQ/
http://www.northamericashaleblog.com/2015/01/13/crude-by-rail-update-municipalities-in-the-bakken-push-back-against-increasing-train-traffic/#commentsTue, 13 Jan 2015 13:49:20 +0000http://www.northamericashaleblog.com/?p=2754Continue Reading]]>Throughout the 19th and early 20th centuries, towns in the western United States grew and thrived around the railroad. In fact, the railroad tracks often became a central geographic feature within towns, birthing the colloquial phrase “the other side of the tracks.” But with increasing train traffic, largely due to unit trains transporting Bakken crude oil, many small-town residents complain that traveling to the other side of the tracks now takes considerably more time.[1]

Frustrated with delays caused by idle trains, two North Dakota towns have taken action to limit the time trains may block railroad crossings.[2] One town—Enderlin—passed an ordinance to that effect in October 2014.[3] Last week, the Enderlin City Council repealed its ordinance in response to a lawsuit and pending preliminary injunction motion filed by Canadian Pacific.[4]

The other town—Berthold—chose a different route. Berthold ordered its police chief to ticket railroads for blocking both the town’s crossings for more than 20 minutes.[5] Rather than pass its own ordinance, Berthold relies on a seemingly little enforced provision of the North Dakota Century Code.[6] Now, BNSF Railway engineers face a penalty of up to 30 days in jail and up to a $1,500 fine under state law for blocking railroad crossings in Berthold.[7]

While Enderlin backed down from its ordinance in the face of Canadian Pacific’s lawsuit, Berthold’s action presents a different hurdle. If BNSF files a lawsuit, BNSF will not be suing a small municipality with limited financial means for extraneous litigation costs. Rather, BNSF must challenge the validity of a state statute, which likely requires the North Dakota Attorney General to defend that law.[8] And unlike the Enderlin City Council quickly repealing its ordinance, the North Dakota Legislature is unlikely to take any action related to the lawsuit.

Although the towns’ actions directly target railroads, if validated by a court, similar ordinances and state laws could induce further delay into a railroad infrastructure already overburdened with record traffic. Furthermore, additional North Dakota municipalities—and potentially towns in other states with similar laws—may begin enforcing the railroad crossing prohibition.

Why should anyone but the railroads care? Other industries should take notice because additional railroad delays mean longer transportation times for all commodities, which impacts, for example, crude oil producers, refineries, farmers, coal producers, and power plants.

Conflicts between commodities—generally attributed to increases in crude-by-rail traffic in North Dakota[9]—have already attracted the attention of the Surface Transportation Board and have pitted industries against one another to secure a timely supply chain.[10] Delays related to local and state interference with railroad operations may draw further attention from the federal regulators, with uncertain results for shipping crude oil by rail.

In the near term, BNSF will likely file a lawsuit, challenging Berthold’s enforcement of the North Dakota law on grounds of federal preemption of railroad operations. If that lawsuit proves unsuccessful, however, more North Dakota municipalities—and other towns in states with similar statutes—may begin enforcing the railroad crossing law. Because of the far-reaching implications of increasing local and state interest in control of railroad operations, trade associations and individual companies should increase the priority of this issue.

[4] Order of Dismissal at 1, Soo Line R.R. Co. v. City of Enderlin,No. 3:14-cv-00106 (D.N.D. Jan. 1, 2015), ECF No. 31 (“[C]ounsel for the City of Enderlin informed the Court that during the evening of January 5, 2015, the Enderlin City Commission voted to repeal the ordinance in dispute.”).

[5] Donovan, supra note 2 (“The police chief in Berthold, a small oil patch town west of Minot, has new marching orders from city hall: Ticket the train engineer the next time a BNSF Railway train blocks both crossings in town for more than 20 minutes.”).

[6] Donovan, supra note 2 (“[January 6, 2015], [Mayor Alan] Lee said the town will rely on state law for writing the ticket and leave it to the court judge to determine what the fine should be, if any.”). See N.D. Cent. Code § 49-11-19(1)–(2) (“A person may not operate any train in a manner as to prevent vehicular use of any roadway for a period of time in excess of ten consecutive minutes . . . . A person that violates this section is guilty of a class B misdemeanor.”).

[7] Donovan, supra note 2; N.D. Cent. Code § 12.1-32-01(6) (“Class B misdemeanor, for which a maximum penalty of thirty days’ imprisonment, a fine of one thousand five hundred dollars, or both, may be imposed.”).

[8]See N.D. Cent. Code § 54-12-01 (listing the duties of the North Dakota Attorney General); About Our Office, N.D. Attorney General, http://www.ag.nd.gov/About/AboutOffice.htm (last visited Jan. 12, 2015). (“[The Attorney General] represents and defends the interests of the state (and therefore, the people) of North Dakota in civil and criminal actions.”).

[10]See id. (“The [STB’s] new data requirements call for railroads to file system-average train speeds for a range of commodities including grain, coal, crude, ethanol and intermodal shipments.”); Energywire, TRANSPORTATION: Railroad Ordered to Share Coal Plan Following Shortages, E & E Publishing (Jan. 8, 2014), http://www.eenews.net/energywire/2015/01/08/stories/1060011297 (“The [STB] has ordered BNSF Railway Co. to share its plan to help keep the lights on in Midwestern states in case of lagging coal deliveries to power plants.”).

]]>http://www.northamericashaleblog.com/2015/01/13/crude-by-rail-update-municipalities-in-the-bakken-push-back-against-increasing-train-traffic/feed/0http://www.northamericashaleblog.com/2015/01/13/crude-by-rail-update-municipalities-in-the-bakken-push-back-against-increasing-train-traffic/Series of Small Earthquakes Hits Dallas Areahttp://feeds.lexblog.com/~r/northamericashaleblog/~3/8prSy4WyTNw/
http://www.northamericashaleblog.com/2015/01/09/series-of-small-earthquakes-hits-dallas-area/#commentsFri, 09 Jan 2015 17:11:37 +0000http://www.northamericashaleblog.com/?p=2747Continue Reading]]>During a span of about 30 hours between the morning of Tuesday, January 6, and the early afternoon of Wednesday, January 7, twelve small earthquakes were confirmed by the United States Geological Survey in the Dallas area. While the tremors, ranging in magnitude from 1.6 to 3.6, have not appeared to cause any injuries or serious damage, local scientists and officials are investigating the causes of the unprecedented amount of seismic activity in the area. Since 2008, the Dallas area has experienced over 100 earthquakes. Prior to 2008, only one earthquake had been recorded in the Fort Worth Basin, which lies beneath the Dallas urban area. A team of researchers led by Professor Brian Stump, a seismologist at Southern Methodist University, is working with local city officials to study the causes of these quakes, although it may be several months before Stump and his team can collect and analyze enough data to make any conclusions.

Although the cause of this latest swarm of earthquakes is currently unknown, some researchers and local residents speculate activities related to hydraulic fracturing could be at least partially to blame, and studies from seismic activity in other parts of the country indicate there is a link between fracing activity and earthquakes. The earthquakes in Texas come just days after researchers, in a new study published in the Bulletin of the Seismological Society of America, concluded that fracing was a cause of 77 small earthquakes (ranging in magnitude from 1.0 to 3.0) between March 4 and March 12, 2014, in the Poland Township, Ohio, area. The study’s lead author, Robert Skoumal, noted that fracing activity “did not create a new fault, [but] rather it activated” a previously unknown one. The study also concluded that fracing operations have to occur fairly close to faults in order to produce earthquakes; thus earthquakes caused by fracing are “pretty rare,” according to Dr. Michael R. Brudzinski, co-author and seismologist at Miami University.

The Poland Township study comes around six months after a report in the journal Science linked over 2,500 minor earthquakes in Oklahoma to four fracing wells. The Oklahoma earthquakes, according to the report, were likely caused by injecting wastewater back into the ground, sometimes near fault lines, after the wells were fracked.

For more information on the earthquakes in Texas, please click here, here and here. For more information on the Poland Township, Ohio, study, please click here, here and here. And for more information on the Oklahoma earthquake study, please click here, here and here.

]]>http://www.northamericashaleblog.com/2015/01/09/series-of-small-earthquakes-hits-dallas-area/feed/0http://www.northamericashaleblog.com/2015/01/09/series-of-small-earthquakes-hits-dallas-area/Louisiana Denies Drilling-Related Permit in Scenic Waterwayhttp://feeds.lexblog.com/~r/northamericashaleblog/~3/OJDagF9P3bw/
http://www.northamericashaleblog.com/2015/01/07/louisiana-denies-drilling-related-permit-in-scenic-waterway/#commentsWed, 07 Jan 2015 18:58:29 +0000http://www.northamericashaleblog.com/?p=2744Continue Reading]]>Louisiana has denied a permit to an energy company seeking to use water from a state-designated scenic river for its drilling operations. The decision represents the first time in Louisiana’s history that a permit to draw water has been denied to a company intending to use water from a protected river for hydraulic fracturing.

Comstock Resources, Inc., a Texas company that operates hydraulic fracturing projects throughout the Gulf Coast, submitted its application in June of last year to pump 12.6 million gallons of water from the Amite River to operate a well in East Feliciana Parish, a region just north of Baton Rouge. Once used, the river water would have been disposed of as hazardous waste.

A number of local and national environmental groups, including the Sierra Club, spoke out against the project. After receiving public comments, the state’s Department of Wildlife and Fisheries, which is charged with overseeing Louisiana’s Natural and Scenic River System, chose to deny the application, despite having issued five similar permits to companies since 2010. In fact, the agency had never before spurned an energy company’s application to draw water from the state’s protected bayous and rivers for hydraulic fracturing operations.

But there is reason to believe that the decision does not spell the end for drilling in Louisiana’s scenic water regions. In its notice of denial, the agency indicated that Comstock’s permit was rejected because two ponds located near the site of the wellhead could be used to satisfy the water needs of the project instead of water from the Amite. In other words, the company may still be able to drill using alternative water sources.

Environmentalists and energy developers must now wait to see how the state will proceed with respect to granting permits in protected rivers and bayous in the future. We will provide updates as this story develops.

]]>http://www.northamericashaleblog.com/2015/01/07/louisiana-denies-drilling-related-permit-in-scenic-waterway/feed/0http://www.northamericashaleblog.com/2015/01/07/louisiana-denies-drilling-related-permit-in-scenic-waterway/Mexico Is Becoming the Single-Largest U.S. Shale Gas Export Customerhttp://feeds.lexblog.com/~r/northamericashaleblog/~3/bv9L8Tliavc/
http://www.northamericashaleblog.com/2015/01/05/mexico-is-becoming-the-single-largest-u-s-shale-gas-export-customer/#commentsMon, 05 Jan 2015 21:19:07 +0000http://www.northamericashaleblog.com/?p=2740Continue Reading]]>On December 2, 2014, President Enrique Peña Nieto inaugurated Phase I of the new Los Ramones Gas Pipeline, which could by year end 2016 double the volume of gas the U.S. exports by pipeline to Mexico.[1] Pipelines to Mexico already move a volume of gas equivalent to more than 16 million tonnes per year of LNG.[2] Once Los Ramones reaches full capacity, U.S. gas producers will be able to export to Mexico more than seven times the annual gas volume that Osaka Gas and Chubu Electric—two of Freeport LNG’s largest LNG export customers—have signed up to purchase.[3]

The first 116 km stage of the pipeline project links Agua Dulce, Texas, to Los Ramones, Nuevo Leon. Phase II of the project is a 738 km line from Los Ramones into Mexico’s industrial heartland, including San Luis Potosí, Guanajuato, and Querétaro.[4] Phase II began construction in August 2014 and will likely enter commercial service by early 2016.[5]

Ultimately, the Los Ramones pipeline system will provide a high-capacity conduit that can move 2 billion cubic feet per day (BCF/d) of Texas shale gas—primarily from the Eagle Ford play—into Mexico’s industrial northeast, including the economic powerhouse of Monterrey, as well as the expanding manufacturing hubs in the Central Mexican states listed above. For comparison, the Eagle Ford Shale presently produces approximately 6 BCF/d of natural gas, according to the EIA.[6]

The U.S.-Mexico gas trade relationship is mutually beneficial. Affordable U.S. shale gas ensures that Mexico’s world-class light industry and manufacturing sectors enjoy competitively priced energy and electricity supplies. In return, Mexican demand for U.S. gas helps relieve the pressure on shale drillers from gas supply saturation in the U.S. domestic market. To illustrate the roots—and results—of Mexico’s manufacturing prowess, consider that on a productivity-adjusted basis, the average Mexican manufacturing wage could be 30% lower than China’s by the end of 2015, while Mexico’s booming auto sector is projected to produce 3.2 million automobiles in 2014, and 4.7 million per year by 2020—a 47% increase.[7]

Mexico’s power sector gas demand is expected to climb from 3.5 BCF/d in 2014 to 5.4 BCF/d by 2024, as electricity demand rises and gas-fired plants’ share of total power generation in Mexico increases from less than 50% now to nearly 70% by 2027, according to the Mexican Secretariat of Energy.[8]

As Mexico’s gas demand climbs, it will continue to favor low-cost U.S. shale gas supplies over expensive LNG imports. Indeed, even the Mexican Secretariat of Energy projects that Mexican LNG consumption will grow very little after 2015 despite gas consumption rising nearly 75% by 2027 from the current level.[9] While Mexico is moving to stimulate private and foreign investment in oil & gas development, established U.S. shale gas producers will likely remain Mexico’s core gas suppliers for at least the next decade as low-cost U.S. supplies flood in through Los Ramones and other cross-border pipelines. Asian markets will buy significant volumes of U.S. LNG when exports commence in late 2015/early 2016, but for the next several years at least, growing cross-border pipeline capacity will make Mexico the largest and steadiest customer for U.S. gas exports.

]]>http://www.northamericashaleblog.com/2015/01/05/mexico-is-becoming-the-single-largest-u-s-shale-gas-export-customer/feed/0http://www.northamericashaleblog.com/2015/01/05/mexico-is-becoming-the-single-largest-u-s-shale-gas-export-customer/U.S. Department of the Interior Launches Online Data Portal Giving Access To Revenue Datahttp://feeds.lexblog.com/~r/northamericashaleblog/~3/HCdW9bmmPCI/
http://www.northamericashaleblog.com/2014/12/16/u-s-department-of-the-interior-launches-online-data-portal-giving-access-to-revenue-data/#commentsTue, 16 Dec 2014 18:15:15 +0000http://www.northamericashaleblog.com/?p=2729Continue Reading]]>Last Thursday, December 11, 2014, the Department of the Interior (“DOI”) became the latest governmental agency to open the doors to some of its data via a new online portal located at https://useiti.doi.gov/.[i]

The new portal is part of the U.S. implementation of the Extractive Industries Transparency Initiative (“USEITI”) and follows President Obama’s May 9, 2013 executive order, making open and machine-readable data the new default for government information:[ii]

“To promote continued job growth, Government efficiency, and the social good that can be gained from opening Government data to the public, the default state of new and modernized Government information resources shall be open and machine readable. Government information shall be managed as an asset throughout its life cycle to promote interoperability and openness, and, wherever possible and legally permissible, to ensure that data are released to the public in ways that can make the data easy to find, accessible, and usable. In making this the new default state, executive departments and agencies (agencies) shall ensure that they safeguard individual privacy, confidentiality, and national security.”

DOI aims via its new portal to increase transparency and allow the public “access [to] detailed revenue data for the development and production of oil, gas, mineral, and other natural resources on Federal lands and offshore on the Outer Continental Shelf.”[iii]

These reported revenue data include parallel public disclosures by both the government and industry of the payments that companies make to the government for oil, gas, and mining resource development.[iv] The data currently available were provided by DOI’s Office of Natural Resources Revenue (“ONRR”), which collects and disburses revenues from energy production on federal onshore and offshore lands and on Indian lands.[v]

At the new portal, the public may view federal resource royalties by location and by sector, and may also view how federal revenue is dispersed and shared. The portal also offers compiled data sets, maps, and graphs–not only by commodity, but also by company.

The “total revenues by company” data set provides calendar year 2013 natural resource revenues data by company. The data set includes revenues for U.S. federal lands and offshore areas, but not Indian lands, privately owned lands, or U.S. state lands.[vi] Selecting a company name allows a user to view rent, bonus, royalty, and other revenue totals by commodity.

The portal is currently in beta, but when fully developed aims to include information on more than 550 companies that meet the minimum payment threshold, currently set at $100,000 per year and determined by the USEITI Multi-Stakeholder Group, a body composed of representatives from government, industry, and civil society.[vii]

]]>http://www.northamericashaleblog.com/2014/12/16/u-s-department-of-the-interior-launches-online-data-portal-giving-access-to-revenue-data/feed/0http://www.northamericashaleblog.com/2014/12/16/u-s-department-of-the-interior-launches-online-data-portal-giving-access-to-revenue-data/Poe Leggette & Alex Obrecht Present on the Safety Concerns that Face Crude-by-Rail Transportationhttp://feeds.lexblog.com/~r/northamericashaleblog/~3/zTm6Ybt22TU/
http://www.northamericashaleblog.com/2014/12/11/poe-leggette-alex-obrecht-present-on-the-safety-concerns-that-face-crude-by-rail-transportation/#commentsThu, 11 Dec 2014 19:50:04 +0000http://www.northamericashaleblog.com/?p=2719Continue Reading]]>BakerHostetler’s energy group co-head and a member of the energy team recently presented on the safety concerns that confront the transportation of crude oil by rail. Focusing primarily on federal regulation, the team explained the role and powers of the Department of Transportation (DOT), the Federal Railroad Administration (FRA), and the Pipeline and Hazardous Materials Safety Administration (PHMSA). Additionally, the team outlined the regulatory efforts to date and discussed the possible outcomes of the current crude-by-rail rulemaking.

Although no strangers to traditional oil and gas regulation, midstream and upstream companies entering crude-by-rail transportation may find themselves facing new regulators, primarily FRA and PHMSA. These agencies can exercise significant power over crude-by-rail transportation, including unannounced inspections,[1] emergency orders,[2] and traditional rulemaking. Noncompliance with the agencies’ mandates may also result in significant civil, and even criminal, penalties.[3]

The federal regulators have exercised each of these powers to address crude-by-rail safety concerns. But these efforts have culminated in the current rulemaking that primarily addresses classification and characterization of crude oil, tank car design, and railroad operating procedures.[4] The rulemaking injects uncertainty as to which tank car design the agencies will adopt, which retrofits will be required for older nonconforming tank cars, and which operating controls will be imposed on high-hazard flammable trains.

]]>http://www.northamericashaleblog.com/2014/12/11/poe-leggette-alex-obrecht-present-on-the-safety-concerns-that-face-crude-by-rail-transportation/feed/0http://www.northamericashaleblog.com/2014/12/11/poe-leggette-alex-obrecht-present-on-the-safety-concerns-that-face-crude-by-rail-transportation/Local and National Environmental Groups Seek to Intervene in Denton Fracking Casehttp://feeds.lexblog.com/~r/northamericashaleblog/~3/BQHaI8u8a3g/
http://www.northamericashaleblog.com/2014/12/09/local-and-national-environmental-groups-seek-to-intervene-in-denton-fracking-case/#commentsTue, 09 Dec 2014 14:20:01 +0000http://www.northamericashaleblog.com/?p=2716Continue Reading]]>On Thursday, December 4, 2014, in Texas Oil and Gas Assoc. v. City of Denton, Cause No. 14-08933-431, 431st District Court, Denton County, Texas, the Denton Drilling Awareness Group and Earthworks filed a Joint Petition in Intervention seeking to “provide a vigorous defense of the legality and enforceability” of the December 2, 2014, ordinance (the “Ordinance”) which banned hydraulic fracturing in Denton. The suit was originally filed on November 5, 2014, by the Texas Oil & Gas Association, a day after Denton voters passed the Ordinance by a 59-41 percent margin.

The Denton Drilling Awareness Group is a Texas nonprofit corporation that created the “Frack Free Denton” campaign and extensively supported the ban. Earthworks is a nonprofit organization based in Washington, D.C., that worked with the Denton Drilling Awareness Group to support the Frack Free Denton campaign and advocated for passage of the fracking ban.

Rule 60 of the Texas Rules of Civil Procedure provides “Any party may intervene by filing a pleading, subject to being stricken out by the court for sufficient cause on the motion of a party.” Tex. R. Civ. P. 60. Although a Texas trial court has broad discretion in determining whether an intervention should be stricken, it is an abuse of discretion to strike a plea in intervention if (1) the intervenor could have brought some or all of the same action in his own name, or if the action had been brought against the intervenor, he could have defeated the action in whole or in part; (2) intervention would not complicate the case by excessive multiplication of the issues; and (3) intervention is almost essential to protect the intervenor’s interest. Guar. Fed. Sav. Bank v. Horseshoe Operating Co., 793 S.W.2d 652, 657 (Tex. 1990).

The Joint Petition in Intervention asserts that a judgment for the Texas Oil & Gas Association would “seriously prejudice” the Denton Drilling Awareness Group and Earthworks due to the “close, continuous, and integral role that Intervenors played in the sponsorship of the initiative and passage of the Ordinance.” Intervenors’ requested relief included the following items: a declaration that the Ordinance is not inconsistent with any state law, rules, or regulations and is valid under the Texas Constitution; a declaration that the Ordinance is not invalidated by the rules or regulations of the Texas Railroad Commission or the Texas Commission on Environmental Quality; and a finding that the Ordinance is valid and fully enforceable by the city of Denton.

]]>http://www.northamericashaleblog.com/2014/12/09/local-and-national-environmental-groups-seek-to-intervene-in-denton-fracking-case/feed/0http://www.northamericashaleblog.com/2014/12/09/local-and-national-environmental-groups-seek-to-intervene-in-denton-fracking-case/Denton Ban Emboldens Fracking Opponents in Other Texas Citieshttp://feeds.lexblog.com/~r/northamericashaleblog/~3/zH-1Jy77728/
http://www.northamericashaleblog.com/2014/12/05/denton-ban-emboldens-fracking-opponents-in-other-texas-cities/#commentsFri, 05 Dec 2014 16:00:55 +0000http://www.northamericashaleblog.com/?p=2711Continue Reading]]>After the first municipal ban on hydraulic fracturing in Texas went into effect on December 2in Denton, residents of other Texas cities are considering whether to pursue bans in their own backyards. Residents from disparate parts of the Lone Star state, including Reno (100 miles northeast of Dallas in Lamar County), Alpine (170 miles southwest of Midland in Brewster County), and Presidio (250 miles southeast of El Paso in Presidio County), have taken notice of the Denton election results.

The Denton ban has become a “proxy for this big war between people who want to stop fracking and people who want to see it happen,” said Michael Webber, deputy director of the Energy Institute at the University of Texas at Austin. Pat Simms, a member of the Presidio County water conservation board, has said that Presidio residents are pushing for a ban on exploratory fracking wells, even some that are being drilled across the border from Presidio in Mexico, which they believe are tainting the city’s water supply. Following a series of tremors in November 2013 that Reno residents believe were related to injection wells surrounding the city, Reno passed a law in April limiting disposal well activity to operators that can prove the injections won’t cause earthquakes. Reno’s mayor, Lyndamyrth Stokes, believes the April law is the first step toward an outright ban on fracking in Reno.

Although none of these municipalities sit atop the heart of any of the major shale formations in Texas, the success of the Denton measure has given hope to opponents of hydraulic fracturing that similar ordinances might have success in their towns.

]]>http://www.northamericashaleblog.com/2014/12/05/denton-ban-emboldens-fracking-opponents-in-other-texas-cities/feed/0http://www.northamericashaleblog.com/2014/12/05/denton-ban-emboldens-fracking-opponents-in-other-texas-cities/To Fracture or Not to Fracture, That Is the Question in Floridahttp://feeds.lexblog.com/~r/northamericashaleblog/~3/Xl2tZv2DrD4/
http://www.northamericashaleblog.com/2014/12/04/to-fracture-or-not-to-fracture-that-is-the-question-in-florida/#commentsThu, 04 Dec 2014 16:01:04 +0000http://www.northamericashaleblog.com/?p=2708Continue Reading]]>Using one line to get to the heart of the matter, on December 2, 2014, two Florida senators filed a bill aimed to ban fracking throughout the state. Senate Bill 166 defines hydraulic fracturing as the process of pumping fluids underground to create fractures in rock for the purpose of producing or recovering oil or gas. Thereafter the legislative action states: “A person may not engage in hydraulic fracturing in this state.” Beyond prohibiting this type of exploration activity, the measure makes no effort to include enforcement provisions or provide any state regulatory agency authority to act. (Text of Senate Bill 166)

Explaining their actions, the senators broadly explained the legislation would protect the state’s water supply, environment and tourism economy. Citing the Everglades and beaches as draws for tourism, the senators said the bill would protect the state’s natural beauty.

The bill apparently responds to the public discussion initiated last week when Florida Power & Light sought permission to form a partnership with an Oklahoma oil and gas company to tap a natural gas well. In the hearing, FPL told the Public Service Commission that its customers would not see price increases from its exploration efforts because the investments in gas production would result in savings that offset the costs. Critics questioned how noneconomic or under-producing wells would be funded; they also raised concerns about the safety and effects of hydraulic fracturing. The PSC should make its decision on FPL’s natural gas exploration request by the end of the year.

Meanwhile, if enacted when the Florida legislature convenes in March 2015, the newly proposed hydraulic fracturing ban would take effect on July 1, 2015.

]]>http://www.northamericashaleblog.com/2014/12/04/to-fracture-or-not-to-fracture-that-is-the-question-in-florida/feed/0http://www.northamericashaleblog.com/2014/12/04/to-fracture-or-not-to-fracture-that-is-the-question-in-florida/Illinois Drilling Rules Dodge First Blow in Latest Lawsuithttp://feeds.lexblog.com/~r/northamericashaleblog/~3/sX6V2gjE6zQ/
http://www.northamericashaleblog.com/2014/12/02/illinois-drilling-rules-dodge-first-blow-in-latest-lawsuit/#commentsTue, 02 Dec 2014 21:09:04 +0000http://www.northamericashaleblog.com/?p=2703Continue Reading]]>Illinois’ fledgling hydraulic fracturing industry avoided another delay last week. The rules, which adopt a regulatory framework to facilitate and regulate unconventional drilling, were finally published after over a year in the works. Last week, the rules faced a preliminary injunction in a pending lawsuit brought by Illinois landowners, who oppose unconventional drilling. However, Judge Barbara Crowder denied the request for a preliminary injunction, explaining that the landowners did not face irreparable harm.

The group of landowners sued the Illinois Department of Natural Resources (IDNR), complaining that it skirted the appropriate rulemaking procedures when it adopted its latest oil and gas regulations. Last summer, Illinois enacted the Hydraulic Fracturing Regulatory Act (HFRA), which gave the IDNR the power to make rules governing the unconventional drilling industry. In August, after considering thousands of public comments, the IDNR handed its draft rules over to the Joint Committee on Administrative Rules (JCAR), which reviewed them until early November. The JCAR had the final word on whether the rules fairly balanced the industry’s and environmentalists’ concerns. On November 6, it approved and published the IDNR’s rules.

Shortly after, on November 10, the group of landowners filed their complaint in the Madison County Circuit Court: Smith et al. v. The Illinois Department of Natural Resources. Among its ten counts, the landowners alleged that the IDNR:

failed to publish the rule in its regulatory agenda;

failed to provide sufficient notice of public hearings;

failed to make an agency official available to answer questions at the public hearings;

denied citizens access to the public hearings;

denied citizens opportunity to speak at the public hearings;

failed to use studies, reports, or data to compose the rules;

provided false statements in its notice of rulemaking;

delayed publishing the transcripts of the public hearing; and

failed to comply with the Illinois HFRA.

The landowners asked for a preliminary and permanent injunction. Judge Crowder denied the preliminary injunction – which required the landowners to prove they are subject to irreparable harm – and has not yet ruled on the merits of the remaining claims.

]]>http://www.northamericashaleblog.com/2014/12/02/illinois-drilling-rules-dodge-first-blow-in-latest-lawsuit/feed/0http://www.northamericashaleblog.com/2014/12/02/illinois-drilling-rules-dodge-first-blow-in-latest-lawsuit/Colorado Oil & Gas Association Seeks Overturn of Broomfield Hydraulic Fracturing Banhttp://feeds.lexblog.com/~r/northamericashaleblog/~3/tJi8-DYiWe4/
http://www.northamericashaleblog.com/2014/11/25/colorado-oil-gas-association-seeks-overturn-of-broomfield-hydraulic-fracturing-ban-2/#commentsTue, 25 Nov 2014 20:13:27 +0000http://www.northamericashaleblog.com/?p=2698Continue Reading]]>On Monday, November 24, the Colorado Oil & Gas Association (COGA) filed a lawsuit in the Broomfield District Court for declaratory judgment to invalidate that city’s temporary ban on hydraulic fracturing. The ban, known as Question 300, passed in November 2013 by 20 votes, places a five-year moratorium on hydraulic fracturing and prohibits storage in open pits and disposal of waste from hydraulic fracturing in Broomfield. Question 300 was put on the ballot by a grassroots group called Our Broomfield, which acted in response to oil and gas company Sovereign’s plans to begin hydraulic fracturing in the North Park area near Prospect Ridge Academy.

Similar drilling bans in Fort Collins, Lafayette and Longmont have already been struck down this year because they violated state law. “Colorado has among the most stringent and well-constructed oil and gas regulations in the nation, and we have a court system that respects the rule of law and rights granted through contractual agreements,” stated COGA President Tisha Schuller in a news release Monday. “For the last three years, COGA has worked diligently to create operating agreements with local jurisdictions that respect the law and meet the needs of local communities. It is my sincere hope that we can get the lawsuits resolved so we can focus on the important and successful work of engaging with our communities.”

In its complaint, COGA asked the court to determine that the ban is “invalid and unenforceable” because it is preempted by state and federal laws. COGA’s position is somewhat strengthened by the fact that the hydraulic fracturing ban does not apply to oil and gas company Sovereign, which won its legal action over the moratorium earlier this year. Sovereign planned to drill new wells in Broomfield in 2013, but was unable to because of the passage of the five-year moratorium. Sovereign then sued, claiming it should be exempt from the moratorium because of a memorandum of understanding it had in place before Question 300 was approved. Judge Chris Melonakis ruled in Sovereign’s favor in September. The city decided not to appeal the decision.

Our Broomfield was disappointed in the decision to allow Sovereign to pursue hydraulic fracturing and in the city’s decision not to appeal the decision. According to Nate Troup, a member of Our Broomfield, the group plans to continue to “pursue protection of our communities and our property values in every way we can.”

Sovereign is permitted to drill in Broomfield per the strict standards set forth in the memorandum of understanding, though it is unknown when or where Sovereign will begin drilling. The moratorium still applies to all other oil and gas operators, even if they have previously drilled in the city and county.

]]>http://www.northamericashaleblog.com/2014/11/25/colorado-oil-gas-association-seeks-overturn-of-broomfield-hydraulic-fracturing-ban-2/feed/0http://www.northamericashaleblog.com/2014/11/25/colorado-oil-gas-association-seeks-overturn-of-broomfield-hydraulic-fracturing-ban-2/EPA Announces New Greenhouse Gas Reporting Rule for Oil and Gas Sectorhttp://feeds.lexblog.com/~r/northamericashaleblog/~3/_blMuDOmfEw/
http://www.northamericashaleblog.com/2014/11/20/epa-announces-new-greenhouse-gas-reporting-rule-for-oil-and-gas-sector/#commentsThu, 20 Nov 2014 16:00:20 +0000http://www.northamericashaleblog.com/?p=2686Continue Reading]]>On Friday, the U.S. Environmental Protection Agency (EPA) announced new rules for reporting greenhouse gas emissions that will apply to the oil and gas sector, part of EPA’s plan to institute a comprehensive strategy for dealing with methane in oil and gas production. The proposed rules would alter the greenhouse emissions reporting program first mandated by Congress in 2008.

Specifically, the new rules will change the calculation methods for oil and gas emissions by changing the units of measurement, altering the equations used for collecting and reporting data, and requiring separate reports for methane, carbon dioxide and nitrous oxide rather than a single category for “carbon dioxide equivalent.” Additionally, the new rules would alter the equations for global warming potential and require oil and gas operators to calculate individual emissions in metric tons.

The proposal predicts that these new rules will “reduce the likelihood of errors and inconsistencies” by “reduc[ing] the number of calculations that need to be completed by reporters” and otherwise improving consistency among reporting entities.

The rule is slated to apply to natural gas transportation and distribution, including by pipeline, as well as petroleum and natural gas extraction.

According to an EPA spokesperson, “The proposed rules would add reporting of GHG emissions from gathering and boosting systems, oil well completions and workovers using hydraulic fracturing (fracking), and blowdowns of natural gas transmission pipelines,” all of which are “areas where GHG emissions data are currently limited.”

Under the current reporting rules, EPA receives regular data from oil and gas production, processing, transmission, and distribution – a total of over 2,100 oil and gas facilities with 224 million metric tons of carbon dioxide equivalent last year.

While it is taking comments for 60 days after the proposals are published in the Federal Register, EPA does not intend to hold public hearings unless requested.

]]>http://www.northamericashaleblog.com/2014/11/20/epa-announces-new-greenhouse-gas-reporting-rule-for-oil-and-gas-sector/feed/0http://www.northamericashaleblog.com/2014/11/20/epa-announces-new-greenhouse-gas-reporting-rule-for-oil-and-gas-sector/The Myth of the Regulatory Gap: BLM’s Proposed Hydraulic Fracturing Rule Compared to Existing State Lawhttp://feeds.lexblog.com/~r/northamericashaleblog/~3/_Ktul5deTaY/
http://www.northamericashaleblog.com/2014/11/19/the-myth-of-the-regulatory-gap-blms-proposed-hydraulic-fracturing-rule-compared-to-existing-state-law/#commentsWed, 19 Nov 2014 16:00:13 +0000http://www.northamericashaleblog.com/?p=2675Continue Reading]]>For the better part of the last decade, oil and natural gas production from domestic wells has increased steadily. Technical advancements in identifying promising sources of oil and gas and extracting hydrocarbons from previously inaccessible formations has allowed domestic producers to reach production levels once thought impossible. Virtually all of this increased production has come through the application of the innovative but controversial well stimulation technique of hydraulic fracturing – the procedure by which oil and gas producers inject water, sand, and certain chemicals into tight-rock formations (typically shale) to create fissures in the rock and allow oil and gas to escape for collection in a well.

But while overall production growth has been profound, the domestic energy renaissance has left behind one important group of potential beneficiaries: American taxpayers. Because although domestic production continues to grow steadily, the percentage of that production that is extracted from federal lands has declined for most of the last decade. At first glance, this divergence should be surprising given that the federal government controls approximately 650 million surface acres – approximately one-third of the nation’s surface area – and over 700 million acres of federal mineral estate, as well as more than 55 million acres of Indian mineral estate. And for oil and gas operators in the western United States, in particular, federal lands are exceedingly difficult to avoid.

Yet notwithstanding the prolific scope of the United States’ holdings, a complex network of regulatory requirements – both existing and proposed – as well as logistical inefficiencies inherent in the federal government’s management of the nation’s public lands represent an enormous incentive for operators to focus their efforts on state and private lands. And now the circumstances creating that incentive are poised to become exacerbated. After a rulemaking process that has lasted almost three years, it is expected that the Bureau of Land Management (“BLM”) will issue proposed regulations to govern hydraulic fracturing on federal and Indian lands within the next several weeks. First proposed in May 2012, and then revised and re-issued in May 2013, the agency characterizes the proposal as an effort to create a uniform standard that will ensure that federal public lands are protected. According to the Secretary of the Interior, BLM “want[s] to make sure that on public lands, [BLM has] very good baseline regulations that the public can feel good about.”

The agency “acknowledges that many States do have regulations in place,” but observes that “not all of the States that contain Federal lands under the BLM’s jurisdiction have hydraulic fracturing regulations.” The suggestion is that BLM must take some action to ensure environmental health and safety, because existing rules are not sufficient to guarantee environmental health and public safety. BLM’s assertion of this “regulatory gap,” however, belies the regulatory framework that already applies to oil and gas operations around the country.

According to the Public Lands Statistics, BLM approved 8,026 APDs on public lands during the last two fiscal years, 2012 and 2013. Of that number, almost ninety-eight percent of the wells approved were in just seven states: California, Colorado, Montana, North Dakota, New Mexico, Utah, and Wyoming. Each of these states have regulations to safely manage hydraulic fracturing operations.

The adequacy of the states’ regulations is even more apparent when one considers the focus of BLM’s proposal. Despite being titled as a rule for “Hydraulic Fracturing on Federal and Indian Lands,” BLM’s proposal does not attempt to govern any aspect of the hydraulic fracturing process specifically. The proposed rules focus instead on: (i) construction standards to ensure well bore integrity; (ii) public disclosure of chemical additives injected during production operations; and (iii) plans for management of water produced during oil and gas operations. Rather than representing new regulations to govern hydraulic fracturing, the proposed rule would constitute little more than an additional layer of regulation applied to traditional elements of conventional oil and gas development.

More important, these are all items that the states have been regulating successfully for decades. The regulatory preamble to BLM’s proposed rule fails to identify a single environmental problem related to hydraulic fracturing that persists under state law but that the proposed rule would remediate; or list a single incident that the new federal rules would have prohibited, but which was not covered under existing state rules.

The tables that follow compare the regulatory requirements of BLM’s proposed rules to those requirements already in place under state law in the seven states where virtually all drilling activity on federal lands occurs. As a review of the tables reveals, the problem with BLM’s pending proposal is not simply that states have hydraulic fracturing rules on the books, but rather that the proposed rule does not provide any benefit commensurate with the costs it will impose. BLM has no evidence that its costly proposed rule will be any more effective in practice than existing state regulations protecting water and other environmental values.

]]>http://www.northamericashaleblog.com/2014/11/19/the-myth-of-the-regulatory-gap-blms-proposed-hydraulic-fracturing-rule-compared-to-existing-state-law/feed/0http://www.northamericashaleblog.com/2014/11/19/the-myth-of-the-regulatory-gap-blms-proposed-hydraulic-fracturing-rule-compared-to-existing-state-law/Ohio Elections Yield Mixed Results on Local Hydraulic Fracturing Banshttp://feeds.lexblog.com/~r/northamericashaleblog/~3/1sm0xgyeXQU/
http://www.northamericashaleblog.com/2014/11/17/ohio-elections-yield-mixed-results-on-local-hydraulic-fracturing-bans/#commentsMon, 17 Nov 2014 16:00:27 +0000http://www.northamericashaleblog.com/?p=2672Continue Reading]]>Last week’s Election Day in Ohio produced victories for fracing supporters and opponents alike. Proposed hydraulic fracturing bans were on the ballot in four different municipal contests. Voters in one city, Athens, approved a ban, while similar legislation was rebuffed in three other municipalities. Looming in the background of these referenda, however, is the Ohio Supreme Court’s anticipated decision in Monroe Falls v. Beck Energy Corporation, which could determine the extent of localities’ authority to regulate fracing activities.

The ban in Athens, a city in the southeastern part of the state, passed in resounding fashion with 78% of the vote. There, voters endorsed legislation that prohibits fracing as well as the transportation of wastewater from any such operations. Although no oil or gas drilling currently occurs within the city’s borders, proponents of the ban say the measure is necessary to protect Athens’s drinking water. City councilman Jeffrey Risner voiced this sentiment: “We’re very cognizant of the fact that if fracking fluids got in there, we could not get them out.”

Less than 200 miles north of Athens, however, Election Day played out quite differently. In the northeastern city of Youngstown, 58% of voters rejected an amendment to the city charter that would have prohibited fracking within the municipality. The vote represents the fourth time in two years that the city’s citizens have spurned such a ban. Prior to the referendum, Youngstown Mayor John A. McNally predicted the ban would not pass, asserting “I don’t see widespread concerns that anything related to shale drilling is a threat to our community.” Similar municipal fracking bans were also rejected by voters in the city of Kent and the village of Gates Mills.

But the enforceability of the Athens ban may ultimately hinge on the Ohio Supreme Court’s decision in Monroe Falls. At issue in that case is whether state-issued drilling permits preempt municipal zoning ordinances that regulate fracing-related activities. The Athens ban could ultimately prove ineffective if the court decides that local ordinances must yield to state permits. The court heard oral arguments in February, and a decision is expected in the near future.

]]>http://www.northamericashaleblog.com/2014/11/17/ohio-elections-yield-mixed-results-on-local-hydraulic-fracturing-bans/feed/0http://www.northamericashaleblog.com/2014/11/17/ohio-elections-yield-mixed-results-on-local-hydraulic-fracturing-bans/Bakken Crude-by-Rail: Environmental Groups Ask New York to Regulate DOT-111 Tank Carshttp://feeds.lexblog.com/~r/northamericashaleblog/~3/iq09PP7TKQU/
http://www.northamericashaleblog.com/2014/11/14/bakken-crude-by-rail-environmental-groups-ask-new-york-to-regulate-dot-111-tank-cars/#commentsFri, 14 Nov 2014 16:00:29 +0000http://www.northamericashaleblog.com/?p=2661Continue Reading]]>A recent state-law challenge by environmental groups to an aspect of crude-by-rail transportation has teed up the question of federal supremacy over railroad regulation. Because federal law generally preempts state regulation of railroads, the environmental groups must fashion their state-law challenges to invoke a traditional area of state regulation—in many instances, land use.1 But a recent petition filed by environmental groups in New York attempts to finagle state regulation over an aspect of rail transportation traditionally preempted by federal law.2

The bottom line is this: Bakken players will continue to face state-law challenges to any midstream or end-user project that transports or receives crude by rail. Effectively managing and combating these challenges will require both Bakken players’ and trade associations’ proactive involvement to monitor and attack environmental groups’ state-law challenges that push the boundaries of permissible state regulation.

With a high-volume horizontal hydraulic fracturing moratorium, New York represents one of the most unfriendly environments for unconventional shale development.3 It comes as no surprise, then, that New York has emerged as a battleground for Bakken crude-by-rail transportation.

On October 20, 2014, Earthjustice, on behalf of numerous petitioners, filed a petition with the New York State Department of Environmental Conservation (“NYSDEC”), requesting a summary abatement order “prohibiting receipt and storage of Bakken crude oil in DOT-111 tank cars” at two transloading facilities and throughout the state of New York.4

The petition claims to invoke the state’s regulatory power over the transloading facilities.5 But by seeking a blanket prohibition on crude oil “receipt and storage” in DOT-111s, the thrust of the petition actually asks the state to regulate a vessel in which federal regulations allow railroads to transport crude.

If New York regulators were to acquiesce to the petition’s demands, the action would impermissibly encroach on federal supremacy over the regulation of railroads.6 Although a proposed federal rule would phase out crude oil transportation in outdated tank cars, current federal law authorizes the transportation of most crude in DOT-111s.7 Because federal law preempts state regulation over railroads, states lack the power to prohibit the vessel in which railroads carry crude oil to transloading facilities.

Anticipating the federal preemption issue, the petition advances two counterarguments. First, the petition argues that federal law governs transloading facilities only when rail carriers own them and that the challenged facilities belong to non-rail carriers.8 But the petition mischaracterizes the scope of its request. Prohibiting the “receipt and storage” of Bakken crude in DOT-111s at the challenged facilities would effectively prevent federally authorized use of the tank cars. The petition’s request impermissibly reaches past mere regulation of the transloading facility by, in effect, dictating to rail carriers which tank cars New York will permit.

Second, the petition relies on the Second Circuit’s decision in Berman Enterprises, Inc. v. Jorling,9 for the proposition that the NYSDEC may issue summary abatement orders even in areas that federal law preempts.10 But the petition conveniently ignores both the facts of Jorling and the narrow holding of the Second Circuit.

In Jorling, the NYSDEC issued a summary abatement order that banned a company’s use of individual barges to transport crude oil, in part, because one barge sank and the company had repeatedly violated state law.11 In stark factual contrast here, the petition seeks to invoke summary abatement powers to ban an entire class of transportation vessel—DOT-111 tank cars—from service within New York.12 In Jorling, the district court specifically upheld the state’s power to regulate barge licensing because: “[p]articular classes of vessels are not barred from New York harbors.”13 But the petition asks New York to bar a class of transportation vessel, which puts the current situation in direct conflict with a crucial fact in Jorling.

Furthermore, the Second Circuit never actually affirmed the district court’s preemption holding.14 It noted that the district court’s “scholarly analysis” rejected the federal preemption claims.15 But the court stated, in dicta with no discussion or analysis, only that: “[p]reliminarily, we agree with Judge Weinstein’s rejection of Berman’s claim that federal law preempts any state regulation of Berman’s barges in New York Harbor.”16

But the court then continued to affirm the district court’s dismissal of Berman’s claims based on grounds entirely unrelated to federal preemption.17 The petition’s assertion that the Second Circuit affirmed New York’s power to issue summary abatement orders in areas that federal law preempts misconstrues the Jorling opinion.

Even though the petition rests on untenable legal grounds, and the NYSDEC will likely take no action on it, the petition still signals a potential trend that environmental groups will increasingly stretch the boundaries of states’ regulatory powers to attack the transportation of crude oil by rail.

Rather than dismiss these questionable challenges, Bakken players that rely on crude-by-rail transportation should actively monitor these emerging challenges and, where permitted, intervene to aggressively argue that federal law preempts state regulation over most aspects of crude-by-rail transportation.

[1] See Rapanos v. United States, 547 U.S. 715, 738 (2006) (Scalia, J., plurality opinion) (“Regulation of land use . . . is a quintessential state and local power.”).

[4] See Earthjustice, supra note 2, at 31. A summary abatement order allows the NYSDEC Commissioner to order a person to “discontinue, abate or alleviate” a condition that “presents an imminent danger to the health or welfare of the people of the state or results in or is likely to result in irreversible or irreparable damage to natural resources.” N.Y. Envtl. Conserv. § 71-0301 (2014).

[10] See Earthjustice, supra note 2, at 5 (“Moreover, the United States Court of Appeals for the Second Circuit has sustained the Commissioner’s summary abatement powers in the face of a federal preemption challenge in remarkably similar circumstances involving imminent harm from transportation of oil and sludge in barges.”); see id. at 29–30 (“Significantly, the Second circuit has affirmed [NYS]DEC’s use of a summary abatement order in circumstances analogous to the present matter. . . . In an analysis of federal preemption that the U.S. court of Appeals for the Second Circuit later affirmed and lauded as ‘scholarly,’ the District court rejected the barge owners’ preemption claim . . . .” (internal citations omitted) (emphasis added)).

[11] Jorling, 793 F. Supp. at 411.

[12] See Earthjustice, supra note 2, at 31 (“Petitioners respectfully request that the Commissioner immediately issue a Summary Abatement Order prohibiting receipt and storage of Bakken crude oil in DOT-111 tank bars by Global and Buckeye at the Albany Terminals, or at any other facility in the State of New York . . . .” (emphasis added)).

]]>http://www.northamericashaleblog.com/2014/11/14/bakken-crude-by-rail-environmental-groups-ask-new-york-to-regulate-dot-111-tank-cars/feed/0http://www.northamericashaleblog.com/2014/11/14/bakken-crude-by-rail-environmental-groups-ask-new-york-to-regulate-dot-111-tank-cars/High Stakes Out on the Range: Gunnison Sage-Grouse Listed as an Endangered Specieshttp://feeds.lexblog.com/~r/northamericashaleblog/~3/yXiVLYk_Bbw/
http://www.northamericashaleblog.com/2014/11/13/high-stakes-out-on-the-range-gunnison-sage-grouse-listed-as-an-endangered-species/#commentsThu, 13 Nov 2014 18:25:34 +0000http://www.northamericashaleblog.com/?p=2642Continue Reading]]>In the first salvo of a larger environmental-industry showdown impacting Western shale development, the U.S. Fish and Wildlife Service announced Wednesday (Nov. 12, 2014) that the Gunnison sage-grouse would be granted endangered-species protection as a “threatened” class. The decision had been delayed for six months while state and local officials in Colorado and Utah undertook extensive conservation measures to avoid the listing.

Both states’ economies benefit from oil and natural gas exploration and production and renewable energy development, and the listing will impact current and future energy-related development efforts. Prior to the decision, Colorado Governor John Hickenlooper promised a lawsuit against the federal government if the agency listed the Gunnison sage-grouse as either “threatened” or “endangered.” After the announcement, Governor Hickenlooper renewed his threat.

(April 2014 photo from the Colorado Department of Parks and Wildlife)

In his press conference, Dan Ashe, director of the Fish and Wildlife Service, explained, “While many people hoped that the extraordinary conservation efforts by our partners in Colorado and Utah would resolve all the threats faced by the Gunnison sage-grouse, the best available science indicates that the species still requires the Act’s protection.”

On its face, the decision will directly impact 1.4 million acres of designated habitat in southwestern Colorado and southeastern Utah where Gunnison sage-grouse make their home. This protection will require a restriction of oil and gas and renewable energy development, including the closures of roads during nesting season, and cessation of the operation of machinery. FWS officials stated that they will closely examine any activity that could threaten the grouse population, and noted that exploration companies will need to consolidate drilling on fewer sites, using directional drilling to minimize surface disturbance and disruption to the habitat. The implications for the wind industry could be even more significant in the area designated by FWS, particularly given the permanent nature of these structures and spacing offsets that will likely be imposed to mitigate impacts on the Gunnison sage-grouse.

However, the real impact lies in the future treatment of the greater sage-grouse, a related species, whose historic range extends across 11 Western states. Aware of this similarity, Director Ashe cautioned against viewing Wednesday’s decision as a predictor of the agency’s future action. Court orders require the agency to issue its ruling on the greater sage-grouse by September 2015.

The fact that the greater sage-grouse’s territory is also prime real estate for oil, gas, wind, solar, coal, and uranium development makes the bird the “big kahuna” for conservationists. To that end, the states and industry still have almost a year to adopt the model formed in Texas and New Mexico to protect the dunes sagebrush lizard. There, conservation agreements between oil and gas operators, renewable energy developers, landowners, and state agencies provided enough protection to the lizard to prevent the federal government from classifying it as an endangered species. In the case of the greater sage-grouse, such conservation agreements could mean voluntary restrictions on development locations and payments into habitat restoration funds.

With billions of dollars per year in economic development at issue, the stakes out on the range are rising, while the fate of the sage-grouse and the energy industry hangs in the balance.

]]>http://www.northamericashaleblog.com/2014/11/13/high-stakes-out-on-the-range-gunnison-sage-grouse-listed-as-an-endangered-species/feed/0http://www.northamericashaleblog.com/2014/11/13/high-stakes-out-on-the-range-gunnison-sage-grouse-listed-as-an-endangered-species/Bakken Crude-by-Rail Update: Transloading Projects Dealt a Setback in Californiahttp://feeds.lexblog.com/~r/northamericashaleblog/~3/YlAZ75POBng/
http://www.northamericashaleblog.com/2014/11/13/bakken-crude-by-rail-update-transloading-projects-dealt-a-setback-in-california/#commentsThu, 13 Nov 2014 17:30:07 +0000http://www.northamericashaleblog.com/?p=2649Continue Reading]]>Recently, we covered environmental groups’ increasing array of state-law challenges to midstream and end users of Bakken crude that transport or receive oil by rail. Since then, a California regulator has admitted to erroneously permitting a crude oil transloading facility without complying with the proper environmental review, and the company has voluntarily returned the permit. These developments signal a setback for recently permitted and proposed transloading facilities. Because the setback likely means that environmental groups will continue to pursue similar state-law challenges in California, Bakken players and trade associations must proactively involve themselves with state and local regulators to ensure valid permitting.

In late September 2014, environmental groups represented by Earthjustice filed a lawsuit in California state court that challenged a transloading facility’s permit.1 The lawsuit alleged that the Sacramento Air Quality Management District violated the California Environmental Quality Act when the district issued the crude oil rail-to-truck transloading permit without public notice and comment.

The district has since admitted that it erroneously issued the permit without the requisite “full CEQA review.”3 The company, InterState Oil, has now voluntarily returned the permit and recently stopped using the facility for crude oil transloading.4

The environmental groups have hailed the relinquished permit as “the first crude transfer project that has been stopped dead in its tracks,”5 but the company’s voluntary return of the permit signals much less.

Assuming that CEQA actually applies to this type of permit, the takeaway from the returned permit is that crude oil midstream and end users must proactively engage state and local regulators about proposed transloading projects to avoid permit invalidation due to noncompliance with CEQA or analogous environmental laws in other states. Compliance with these laws undoubtedly means project delays,6 but ensuring that the project adheres to the proper permitting procedures will help prevent additional delays and costs caused by subsequent operational interruptions.

]]>http://www.northamericashaleblog.com/2014/11/13/bakken-crude-by-rail-update-transloading-projects-dealt-a-setback-in-california/feed/0http://www.northamericashaleblog.com/2014/11/13/bakken-crude-by-rail-update-transloading-projects-dealt-a-setback-in-california/Railroad Commission Chairwoman: “It’s My Job to Give Permits, Not Denton’s”http://feeds.lexblog.com/~r/northamericashaleblog/~3/gWLFpOyn2-8/
http://www.northamericashaleblog.com/2014/11/11/railroad-commission-chairwoman-its-my-job-to-give-permits-not-dentons/#commentsTue, 11 Nov 2014 15:02:05 +0000http://www.northamericashaleblog.com/?p=2640Continue Reading]]>At a November 6 event, Texas Railroad Commission Chairwoman Christi Craddick unequivocally stated that the Commission would continue to issue drilling permits to operators in Denton, despite the November 4 vote making it the first city in Texas to ban hydraulic fracturing. “It’s my job to give permits, not Denton’s. We’re going to continue permitting up there because that’s my job,” said Craddick at an event sponsored by the Texas Tribune.

Chairwoman Craddick’s comments are similar to the arguments raised in the lawsuits filed last week by the Texas General Land Office and the Texas Oil and Gas Association, which assert that Denton’s municipal fracking ban is preempted by the Texas constitution and statewide laws governing the development of oil and gas.

The North America Shale Blog will continue to monitor developments in the litigation related to the Denton fracking ban.

]]>http://www.northamericashaleblog.com/2014/11/11/railroad-commission-chairwoman-its-my-job-to-give-permits-not-dentons/feed/0http://www.northamericashaleblog.com/2014/11/11/railroad-commission-chairwoman-its-my-job-to-give-permits-not-dentons/“Frac Free Denton” Faces Legal Fighthttp://feeds.lexblog.com/~r/northamericashaleblog/~3/dolnIq9wOe0/
http://www.northamericashaleblog.com/2014/11/07/frac-free-denton-faces-legal-fight/#commentsFri, 07 Nov 2014 15:39:05 +0000http://www.northamericashaleblog.com/?p=2637Continue Reading]]>On November 4, 2014, Denton, Texas, became the first Texas city to vote to ban fracking within city limits, as covered by Reuters, the Star-Telegram, and The Wall Street Journal. The ballot initiative, which passed with just short of 59 percent of the vote, will require the Denton City Council to sign an ordinance reflecting the election results and ban fracking within Denton city limits.

The North American Shale Blog has been tracking the history of this ballot initiative. See our posts on:

As expected, the Texas General Land Office and the Texas Oil and Gas Association, immediately filed independent lawsuits to prevent the city from enacting the ordinance. The Texas General Land Office filed its case in Travis County while the Texas Oil and Gas Association case was filed in Denton County. Both lawsuits, filed within minutes of the courts opening on November 5th, argue that the ban is unconstitutional under Texas law. They ask the courts to find that Denton’s ban is preempted by the state Constitution and statutes regulating oil and gas development.

While Texas law on preemption is not as well-developed as that of other states that have tackled this issue, the Denton ordinance could force courts to clarify the role local governments can play in regulating oil and gas development. Specifically, Texas courts are being asked to decide whether:

The state regulations are so comprehensive that a local ordinance which is inconsistent with or interferes with such regulation is preempted.

While purporting to only limit hydraulic fracturing and not all drilling, the ban is in fact a de facto ban on drilling given the geology of the Barnett Shale.

A local government can ban conduct, such as hydraulic fracturing, which the State permits.

Although not raised in these first two lawsuits, the specter of an unconstitutional “takings” claim by mineral right owners – similar to that filed in response to Denton’s moratorium on drilling – will continue to haunt the ban until such a claim is ripe for review. It also remains to be seen whether the Texas legislature will allow this decision to remain with the courts, or whether it will attempt to pass legislation clarifying the authority of State agencies as the final arbiters of oil and gas regulation.

Those with interests in the Denton area, the Barnett Shale, or the future of fracking operations in Texas, should continue to watch the North American Shale Blog for updates related to the ordinance and the legal challenges.

]]>http://www.northamericashaleblog.com/2014/11/07/frac-free-denton-faces-legal-fight/feed/0http://www.northamericashaleblog.com/2014/11/07/frac-free-denton-faces-legal-fight/Study Linking Earthquakes to Fracing May Shake the Ballotshttp://feeds.lexblog.com/~r/northamericashaleblog/~3/eyOca9d-VgQ/
http://www.northamericashaleblog.com/2014/11/04/study-linking-earthquakes-to-fracing-may-shake-the-ballots/#commentsTue, 04 Nov 2014 17:05:01 +0000http://www.northamericashaleblog.com/?p=2633Continue Reading]]>On October 15, seismologist Paul A. Friberg published an article in the journal Seismological Research Letters that links earthquakes to hydraulic fracturing. The report was published less than a month before today’s vote, in which several communities will make decisions affecting the burgeoning domestic energy business.

The article links hydraulic fracturing, not only to the more common imperceptible low-magnitude earthquakes, but also to larger, positive-magnitude earthquakes. Friberg lists Oklahoma and Ohio as locations where such earthquakes have been observed. In particular, the report shows that hydraulic fracturing in Harrison County, Ohio is linked to positive-magnitude earthquakes on a previously unmapped fault. Texas, Ohio, and California have all adopted regulations designed to prevent earthquake-related drilling accidents, but the study will still likely trouble voters.

]]>http://www.northamericashaleblog.com/2014/11/04/study-linking-earthquakes-to-fracing-may-shake-the-ballots/feed/0http://www.northamericashaleblog.com/2014/11/04/study-linking-earthquakes-to-fracing-may-shake-the-ballots/Texas Railroad Commission Adopts Rules for Disposal Wells in Potential High-Risk Seismic Areashttp://feeds.lexblog.com/~r/northamericashaleblog/~3/sOvySywmUNM/
http://www.northamericashaleblog.com/2014/10/30/texas-railroad-commission-adopts-rules-for-disposal-wells-in-potential-high-risk-seismic-areas/#commentsThu, 30 Oct 2014 15:07:37 +0000http://www.northamericashaleblog.com/?p=2628Continue Reading]]>On Tuesday, October 28, 2014, the Texas Railroad Commission unanimously adopted amendments to rules concerning disposal wells in areas that have experienced or are likely to experience seismic activity. As covered by the North America Shale Blog in August, the amendments were proposed in response to questions from residents in towns sitting atop the Barnett Shale Formation in North Texas of whether a connection exists between disposal wells, which are used to dispose of saltwater and fluids used in hydraulic fracturing operations, and increased seismic activity in the area.

The amendments adopted on Tuesday take effect on November 17, 2014. The highlights of the amended rules are as follows:

Applicants for new disposal wells are required to conduct a search of the U.S. Geological Survey seismic database for historic seismic activity in a 100-square mile area from the proposed disposal well site;

The Railroad Commission now has authority to modify or suspend or terminate a disposal well permit if it is determined that a disposal well is likely to be or determined to be contributing to seismic activity;

Operators may be required to disclose current annually reported volumes and pressures for disposal wells on a more frequent basis if the Railroad Commission has a need for this information;

Disposal well permit applicants may be required to provide information related to pressure front boundary calculations and demonstrate that disposal fluids will remain confined if the disposal well is determined to be located in a high-risk seismic area; and

The Railroad Commission has estimated that the probable cost for disposal well applicants to comply with the adopted amendments is an additional $300 per permit application.

The most notable change between the proposed rule and the final rule relates to Railroad Commission’s authority to potentially require a disposal well permit applicant to provide pressure front boundary calculations. The proposed rule would have required each applicant to provide information from the U.S. Geological Survey regarding the locations of any historical seismic events within the estimated radius of the 10-year, five pounds per square inch (PSI) pressure front boundary of the proposed disposal well location. The final rule provides that pressure front boundary information may be required in areas that exhibit complex geology or have a history of seismic activity.

Railroad Commission Chairman Christi Craddick believes the amended rules “follow science in protecting our natural resources while at the same time providing a stable regulatory environment for our oil and gas operators.” Commissioner David Porter stated that the “rule amendments will allow us to further examine seismic activity in Texas and gain an understanding of how human activity may impact seismic activity, while continuing to allow for the important development of our energy resources in Texas.”

]]>http://www.northamericashaleblog.com/2014/10/30/texas-railroad-commission-adopts-rules-for-disposal-wells-in-potential-high-risk-seismic-areas/feed/0http://www.northamericashaleblog.com/2014/10/30/texas-railroad-commission-adopts-rules-for-disposal-wells-in-potential-high-risk-seismic-areas/City of Fort Collins, Colorado, Appeals Ruling Striking Down Fracking Banshttp://feeds.lexblog.com/~r/northamericashaleblog/~3/3QeYWTqsIUs/
http://www.northamericashaleblog.com/2014/10/28/city-of-fort-collins-colorado-appeals-ruling-striking-down-fracking-bans/#commentsTue, 28 Oct 2014 16:17:42 +0000http://www.northamericashaleblog.com/?p=2626Continue Reading]]>The week of September 22, the Fort Collins, Colorado, City Council voted to appeal a decision rendered last month that struck down the city’s fracking ban. The North America Shale Blog previously covered that decision here.

In that August 2014 decision, a Larimer County District Court Judge ruled that Colorado’s 1951 Oil and Gas Conservation Act (“Act”) preempts the city’s five-year moratorium on fracking that was set to expire on August 5, 2018. The decision addressed the conflict between Article XX of the Colorado Constitution, which gives local governments “home-rule” powers—defined as “the full right to self-government” on local and municipal matters—and local attempts to regulate oil and gas activities. The court reasoned that Article XX does not permit a city to enact ordinances in areas of mixed state and local concern, or areas of statewide concern that intrude on state law, meaning that a local ordinance may be preempted where it would “conflict with the operation of a state statute.” The court then reasoned that the Act impliedly, though not expressly, preempted the city’s five-year fracking ban because it impeded the state’s interest in oil and gas development.

The Fort Collins resolution council voted 6-1 on Tuesday to direct the city’s interim attorney to appeal that decision to the Colorado Court of Appeals and to seek a stay pending appeal. If successful, a stay of the decision would leave the fracking ban in place pending the outcome of the appeal. Before the vote, several citizens, including a representative of the group Citizens for a Healthy Fort Collins, made public comments in support of the appeal. This appeal will make Fort Collins the second Colorado city to appeal a decision striking down a local fracking ban. Fort Collins follows Longmont, Colorado, where a coalition of environmental groups appealed a similar Boulder County District Court decision to the Colorado Court of Appeals in September.

]]>http://www.northamericashaleblog.com/2014/10/28/city-of-fort-collins-colorado-appeals-ruling-striking-down-fracking-bans/feed/0http://www.northamericashaleblog.com/2014/10/28/city-of-fort-collins-colorado-appeals-ruling-striking-down-fracking-bans/Multistate Regulators Meet in Columbus, Discuss Seismic Activityhttp://feeds.lexblog.com/~r/northamericashaleblog/~3/y1Z4kZEqxGw/
http://www.northamericashaleblog.com/2014/10/27/multistate-regulators-meet-in-columbus-discuss-seismic-activity/#commentsMon, 27 Oct 2014 19:54:31 +0000http://www.northamericashaleblog.com/?p=2622Continue Reading]]>From October 19th to 21st, the Interstate Oil and Gas Compact Commission hosted its 2014 annual conference in Columbus, Ohio. The organization is a collection of regulators from states in which there is significant oil and natural gas exploration and development, and it advocates for states’ rights to govern petroleum resources within their borders. One of the key topics at the conference was reported to be the potential implications of recent news published in a study in the journal Seismological Research Letters that numerous, unnoticeable earthquakes in Harrison County, Ohio, likely were connected to oil and natural gas exploration activities. The earthquakes ranged from magnitude 1.7 to 2.2 on the Richter scale, and 190 of them occurred in the 39 hours after hydraulic fracturing activity occurred at one well in late September and early October 2013. It has been suggested that this is the fifth documented instance of a linkage between hydraulic fracturing earthquakes on a fault.

One source indicated that, if the Ohio Department of Natural Resources’ recently-announced regulations had been in place when these earthquakes occurred, drilling activity in the state would have been halted. The stricter regulations, previously discussed on this blog, were announced in response to an earlier connection suggested by the Ohio Department of Natural Resources between hydraulic fracturing activity, seismic activity, and what is believed to be a previously unknown microfault near Youngstown, Ohio. It remains unclear whether the links posited by this latest study will lead to further regulatory action, but the BakerHostetler North America Shale Blog will keep readers apprised of developments.

]]>http://www.northamericashaleblog.com/2014/10/27/multistate-regulators-meet-in-columbus-discuss-seismic-activity/feed/0http://www.northamericashaleblog.com/2014/10/27/multistate-regulators-meet-in-columbus-discuss-seismic-activity/Uncertainty Prevails as Illinois Delays a Decision on Fracing Regulationshttp://feeds.lexblog.com/~r/northamericashaleblog/~3/dgERPCNtVJk/
http://www.northamericashaleblog.com/2014/10/22/uncertainty-prevails-as-illinois-delays-a-decision-on-fracing-regulations/#commentsWed, 22 Oct 2014 15:56:18 +0000http://www.northamericashaleblog.com/?p=2620Continue Reading]]>Last week, Illinois’s Joint Committee on Administrative Rules voted to push back its decision about whether to approve proposed rules governing horizontal fracturing operations until November 6. The delay promises to fuel uncertainty among fracing supporters and opponents alike about the legality of conducting unconventional drilling operations within the State if the draft rules are not ultimately adopted.

If the committee chooses not to accept the regulations by November 15, the Illinois Department of Natural Resources (IDNR)—the agency responsible for promulgating the standards—is obligated to restart the rulemaking process which promises to further postpone the implementation of state-wide standards for the foreseeable future. IDNR officials have said that the agency will not approve any unconventional drilling permits without rules in place, unless told otherwise by the courts.

Oil and gas companies have refrained from conducting unconventional drilling while the regulations are in limbo. Brad Richards, an executive of the Illinois Oil and Gas Association, described the current situation: “I think most of the [pro-fracing] coalition have been working under the assumption that we have to get [the rules approved] or this just starts over, short of a court order.” He also pointed out that some oil and gas drillers have withdrawn from Illinois due to delays in passing the state-wide standards. Some environmental groups have also expressed uncertainty about what will happen if the rules are not approved in November and want assurances that horizontal drilling will not be conducted in the state without regulations in place.

In response to the committee’s decision, a small group of mineral rights owners in southern Illinois have filed suit against the State, Governor Matt Quinn, and IDNR head Marc Miller. The plaintiffs say they represent a class that exceeds 1,000 people. In their complaint, the plaintiffs claim to have been denied permits to conduct fracing operations designed to take advantage of their mineral rights, which they allege constitutes a “taking of property without just compensation.” The case is called Pollard et al. v. Illinois and was filed in the Circuit Court for the Second Judicial District of Wayne County.

]]>http://www.northamericashaleblog.com/2014/10/22/uncertainty-prevails-as-illinois-delays-a-decision-on-fracing-regulations/feed/0http://www.northamericashaleblog.com/2014/10/22/uncertainty-prevails-as-illinois-delays-a-decision-on-fracing-regulations/An Update on Recent Oil- and Gas-Related Decisions in Ohiohttp://feeds.lexblog.com/~r/northamericashaleblog/~3/X-mKE5fbYrM/
http://www.northamericashaleblog.com/2014/10/21/an-update-on-recent-oil-and-gas-related-decisions-in-ohio/#commentsTue, 21 Oct 2014 18:22:16 +0000http://www.northamericashaleblog.com/?p=2618Continue Reading]]>Due to increased drilling activity in the Utica shale formation, state and federal courts in Ohio and the 6th Circuit have recently issued decisions related to local drilling regulations, drilling permits, leasing, indemnity provisions, and whether a landowner can state a strict liability claim against a drilling company that survives a motion to dismiss. While separate, future blog entries will discuss in more detail Ohio’s Dormant Mineral Rights Act and strict liability claims against fracking operations, the following post summarizes some recent developments in Ohio law that are relevant to the oil and gas industry.

Obstacles to Drilling:

Local Laws and Ordinances—State Ex Rel Morrison v. Beck Energy (9th Dist. – Appeal Pending): Beck Energy received a drilling permit from the Ohio Dept. of Natural Resources to drill in the City of Munroe Falls. As Beck Energy prepared to begin drilling, however, the City successfully sued for an injunction by arguing that Beck Energy was not in compliance with local laws and ordinances related to zoning and rights-of-way. Beck Energy appealed the injunction, and the issue before the appeals court was whether the City can enforce its ordinances governing oil and gas drilling when (1) Beck Energy had received a valid drilling permit and (2) the state has a comprehensive statutory scheme regarding oil and gas drilling. The appeals court ruled that the rights-of-way ordinances regarding the care and supervision of public roads did not directly conflict with the state’s regulatory regime and could be enforced. The Court struck down the local ordinances related to local drilling permits, application fees, and performance bonds as being duplicative of and preempted by state laws and regulations. The Ohio Supreme Court heard this case on appeal on February 26, 2014 but has yet to issue a ruling.

Lease Extensions—Eastham v. Chesapeake Appalachia, LLC (6th Circuit interpreting Ohio law – June 2014): Chesapeake was the successor-in-interest to a lease with the Easthams which provided that “Upon the expiration of this lease . . . Lessor grants Lessee an option to extend or renew under similar terms a like lease.” Without negotiation or notice to the Easthams, Chesapeake filed to extend the lease for another 5 years under the same terms. The Easthams brought suit, arguing that the option language of the lease required negotiations for a “like lease.” The Court sided with Chesapeake, holding that to “extend” a lease means to carry forward the same terms and to “renew” a lease means that the terms of the new lease can be changed slightly.

Arbitration Clauses—New Hope Community Church v. Patriot Energy Partners (7th Dist. – Dec. 2013): The Court held that arbitration clauses in oil and gas drilling leases are valid unless they are both substantively and procedurally unconscionable. The substantive unconscionability inquiry considers the costs of arbitration versus a lawsuit, the specificity of the arbitration provision, the prominence of the provision in the lease, and whether the arbitration provision applies equally to the parties. The procedural unconscionability inquiry considers the negotiators’ relative sophistication, whether the party seeking to enforce the provision also drafted the contract, the relative bargaining power of the parties, and whether the party against which the arbitration provision is being enforced was able to provide alterations to the lease. In this case, the Court found the arbitration provision substantively unconscionable because it was costly, lacked specificity, and was misleading. However, the provision was not procedurally unconscionable because the parties were experienced with oil and gas leases, had the opportunity to consult legal advisors, and there was no evidence of coercion. As a result, the Court ruled that the arbitration provision was valid and enforceable.

Lease Assignments—Harding v. Viking Int’l Resources Co. (4th Dist. – Nov. 2013): Harding entered into a lease with Carlton Oil Corp. that included an anti-assignment clause stating that “The rights and responsibilities of the Lessee may not be assigned without the mutual agreement of the parties in writing.” Without getting a written agreement, Carlton assigned the contract to Viking Int’l Resources. Harding accepted and cashed Viking’s royalty checks for 8 months before objecting to the assignment. In Ohio, contracts can be assigned unless: (1) there is clear contractual language to the contrary; (2) the assignment materially changes the duty of the obligor, increases their risk, or reduces the contract’s value; or (3) the assignment is forbidden by statute or public policy. Despite the fact that Harding cashed Viking’s royalty checks for 8 months, the Court invalidated the assignment but ruled that the lease between Harding and Carlton remains in effect.

Potential Liability:

Reciprocal Indemnity Clauses—Warren Drilling v. Equitable Production (S.D. Ohio – April 2014): A landowner brought a water contamination lawsuit against Warren Drilling. Warren settled the lawsuit with the landowner and then brought an indemnity action against its drilling partner, Equitable Production. The issue before the Court was whether the indemnity provision was enforceable where there was no judicial finding of fault or liability because of the pre-trial settlement. The Court (applying Pennsylvania law) held that Equitable Production did owe indemnity to Warren for its cost of defense and the settlement amount because the indemnity provision required Equitable Production to indemnify Warren for “claims” and “demands” and included a “duty to defend.” The Court indicated that had the indemnity provision been limited to “loss and indemnity” it likely would not have covered a pre-trial settlement with no judicial determination of fault.

Strict Liability—Boggs v. Landmark 4 LLC (N.D. Ohio): Boggs (a private landowner) brought a water contamination lawsuit against Landmark drillers alleging, among other claims, that hydraulic fracturing is an “abnormally dangerous activity” and is, therefore, subject to strict liability. On a motion to dismiss, the Court reviewed the six Restatement factors for determining whether an activity is abnormally dangerous and ruled that Boggs had adequately stated a strict liability claim. Boggs’s strict liability claim was ultimately dismissed after discovery.

]]>http://www.northamericashaleblog.com/2014/10/21/an-update-on-recent-oil-and-gas-related-decisions-in-ohio/feed/0http://www.northamericashaleblog.com/2014/10/21/an-update-on-recent-oil-and-gas-related-decisions-in-ohio/Suit by Denton, Texas, Royalty Interest Owners Could be Harbinger of More Suits If Proposed Hydraulic Fracturing Ban Passeshttp://feeds.lexblog.com/~r/northamericashaleblog/~3/CAreiBpWu40/
http://www.northamericashaleblog.com/2014/10/14/suit-by-denton-texas-royalty-interest-owners-could-be-harbinger-of-more-suits-if-proposed-hydraulic-fracturing-ban-passes/#commentsTue, 14 Oct 2014 14:09:50 +0000http://www.northamericashaleblog.com/?p=2613Continue Reading]]>Ahead of the November 4th vote that could make it the first city in Texas to ban hydraulic fracturing, the City of Denton has been sued by a group of royalty interest owners claiming that the city’s current temporary ban violates their property rights. As previously covered by the North America Shale Blog, on May 6, 2014, the Denton, Texas, city council enacted a drilling moratorium which prohibited the acceptance, receipt, processing, or approval of applications for gas well permits within the Denton city limits.

On September 29, 2014, Charles Chandler Davis filed suit in the 431st District Court of Denton County on behalf of his company, Arsenal Minerals and Royalty, NASA Energy Corp., and his son’s trust fund, claiming damages in excess of $1 million. The City of Denton has removed the suit to the United States District Court of the Eastern District of Texas. Davis’s suit alleges claims related to mineral takings, and states that prior to filing suit, Plaintiffs sought a “takings impact assessment”, which Plaintiffs allege the City should have conducted to determine the impact of the drilling moratorium.

Beyond the suit by Davis, various energy industry representatives have stated their intention, if the hydraulic fracturing ban passes, to file similar takings suits. At the July 15, 2014, meeting where the Denton City Council voted 5-2 to reject the proposed ban and set up the November 4th vote, Tom Phillips, a former chief justice of the Texas Supreme Court who is currently representing the Texas Oil & Gas Association, stated that “some members of [the Texas Oil and Gas Association] will undoubtedly sue.” Phillips also broadcast his belief that if citizens in Denton wish to ban hydraulic fracturing they should seek to do so at the state-wide, rather than municipal, level. “If they want Texas law to ban hydraulic fracturing, they should take their cause to the Texas Legislature. That is the only governing body in the state with the authority to grant the relief they seek.” Rep. Phil King, R-Weatherford, said the most likely action the legislature would take on the issue would be to outlaw cities from passing bans. “If it passes in Denton, I feel very confident that there will be legislation—in fact, I’ll probably file it myself—to prohibit cities from total bans on fracking,” he said.

]]>http://www.northamericashaleblog.com/2014/10/14/suit-by-denton-texas-royalty-interest-owners-could-be-harbinger-of-more-suits-if-proposed-hydraulic-fracturing-ban-passes/feed/0http://www.northamericashaleblog.com/2014/10/14/suit-by-denton-texas-royalty-interest-owners-could-be-harbinger-of-more-suits-if-proposed-hydraulic-fracturing-ban-passes/North Dakota Reminds Negotiators: Be Careful What You Sayhttp://feeds.lexblog.com/~r/northamericashaleblog/~3/sPa4pEsCrT8/
http://www.northamericashaleblog.com/2014/10/10/north-dakota-reminds-negotiators-be-careful-what-you-say/#commentsFri, 10 Oct 2014 19:54:01 +0000http://www.northamericashaleblog.com/?p=2611Continue Reading]]>Do you think that what you say when negotiating a mineral lease does not matter once the agreement is inked and contains boilerplate language declaring it to “supersede all prior negotiations” and “be the complete agreement between the parties”? Think again. The North Dakota Supreme Court recently reminded negotiators that what you say does matter and may allow for rescission of a lease.[1]

This issue came before the North Dakota courts when Golden Eye Resources (“GER”) sought to quiet title in certain oil and gas leases in Williams County, leases that the mineral owners claimed had been cancelled. The minerals owners contend they made it clear at the outset of negotiations that they would only lease to a company which could drill and operate the wells itself. They also contend that GER made representations to this effect during negotiations and thus, despite being approached by another potential lessee offering more favorable financial terms, the mineral owners entered into leases with GER.

When the mineral owners learned that another company had obtained a drilling permit in a drilling unit encompassing some of their minerals, and that GER only has a 19% interest in the spacing units where their minerals were located, they sent GER a notice of rescission. The notice sought to rescind the lease for fraud in the inducement. The matter escalated when, a month later, GER entered into a Participation Agreement, assigning a 58.32% working interest in the drilling unit to another company. The mineral owners then sent a notice of cancellation of the leases, alleging breach of the anti-assignment provisions.

GER responded by suing to quiet title to the leased interests, and while the district court was swayed, the North Dakota Supreme Court was not. On appeal, the Supreme Court held that the district court erred in granting summary judgment dismissing the mineral owners’ claims they were fraudulently induced into signing the leases by GER’s alleged misrepresentations.

As a threshold matter, the Court addressed whether evidence of the parties negotiations leading up to execution of the leases was admissible despite the fact that some purported representations conflicted with certain lease terms; or whether the parol evidence rule barred consideration of such negotiations.[2] Holding that the parol evidence rule does not apply where one of the parties alleges fraud as a defense to the validity of the contract, the Court found it to be immaterial that the alleged oral statements contradicted terms in the written agreement. A boilerplate contract integration clause will not protect a lessee if a mineral owner feels he or she has been misled during lease negotiations.

The remainder of the Court’s opinion serves as a reminder of the line landmen walk between non-actionable “sales talk, puffery, and opinion” and “actual fraud.” In North Dakota actual fraud “includes statements of fact which the party does not believe to be true, the suppression of material facts by one having knowledge or belief of the fact, and a promise made without any intention of performing it.” The following statements allegedly[3] made by GER’s negotiators amounted to actual fraud since they averred past or present facts which GER knew to be untrue:

The company was going to drill the wells itself and would not assign the leases;

It had already acquired thousands of mineral acres in the same township;

It had someone in Bismarck securing drilling permits on the acreage it had already acquired;

The company had operating/drilling control over the sections where the potential lessee’s minerals were located;

It would drill lessee’s minerals first;

It had successfully drilled wells in Canada; and

The company’s owner owned his own equipment and was very experienced in drilling horizontal wells.

Although negotiators are already mindful of being fair and honest in dealing with landowners, this opinion cautions that negotiation tactics are still open to scrutiny even after the lease is signed. As the North Dakota Supreme Court warns, “consent is not free if obtained through fraud” and without consent there is no lease.

[1] Golden Eye Resources v. Ganske, 2014 ND 179 (Sept. 23, 2014).

[2] North Dakota has codified the parol evidence rule which provides: “The execution of a contract in writing, whether the law requires it to be written or not, supersedes all the oral negotiations or stipulations concerning its matter which precede or accompanies the execution of the instrument.” N.D.C.C. § 9-06-07. Other states have similarly adopted some iteration of the parol evidence rule. See, e.g., Colorado (C.R.S. § 4-2-202); Ohio (R.C. § 1302.05); Pennsylvania (Yocca v. Pittsburgh Steelers Sports, Inc., 578 Pa. 479, 854 A.2d 425 (2004)).

[3] Because the court on summary judgment must accept the non-moving party’s allegations as true, this opinion also serves as a reminder to practitioners that it may be very difficult to overcome a fraudulent inducement defense on summary judgment.

]]>http://www.northamericashaleblog.com/2014/10/10/north-dakota-reminds-negotiators-be-careful-what-you-say/feed/0http://www.northamericashaleblog.com/2014/10/10/north-dakota-reminds-negotiators-be-careful-what-you-say/Environmental Groups Ramp-up the Crude-by-Rail Fight in the Courtroomhttp://feeds.lexblog.com/~r/northamericashaleblog/~3/BgFY5Y29S8c/
http://www.northamericashaleblog.com/2014/10/06/environmental-groups-ramp-up-the-crude-by-rail-fight-in-the-courtroom/#commentsMon, 06 Oct 2014 18:54:26 +0000http://www.northamericashaleblog.com/?p=2608Continue Reading]]>Bakken crude producers and midstream transportation companies already experience transportation woes related to inadequate pipeline infrastructure, railroad capacity, tank car supply, rail accidents, and new regulations. But they also increasingly face a new problem: lawsuits. In September alone, the Sierra Club, one of the largest environmental organizations in the United States, filed two lawsuits challenging different aspects of crude-by-rail transportation. First, on the national level, the Sierra Club seeks to stop the transportation of crude oil in allegedly outdated and unsafe tank cars. And second, at the state level, the Sierra Club accuses a local agency of illegally permitting a rail-to-truck facility.

The first lawsuit challenges the continued use of older DOT-111 tank cars, the tank car commonly used to transport Bakken crude oil.[i] On July 15, 2014, the Sierra Club and ForestEthics, through Earth Justice (collectively “petitioners”), petitioned the United States Department of Transportation (“DOT”), asking for an “emergency order prohibiting the shipment of Bakken crude oil in unsafe tank cars” (“Rail Car Petition”).[ii] The petitioners allege that shipping crude oil in these unsafe “legacy DOT-111” tank cars poses an “imminent hazard” requiring the immediate cessation of their use.[iii] Roughly a month after receiving the Rail Car Petition, the DOT, through the Pipeline and Hazardous Materials Administration and the Federal Railroad Administration, issued a proposed rule that addresses many of these concerns.[iv]

Although the proposed rule addresses many of the DOT-111 safety concerns, the petitioners believe the rulemaking process will take too long.[v] On September 11, 2014, the environmental groups filed suit in the United States Court of Appeals for the Ninth Circuit.[vi] The petitioners ask the court to order the DOT to respond to the Rail Car Petition.[vii] As its legal basis, the environmental groups argue that under the Administrative Procedure Act the DOT has taken an unreasonable amount of time to respond to the Rail Car Petition.[viii] The Ninth Circuit denied the petitioners’ request for an expedited decision and ordered the DOT to respond.[ix] The court specifically directed the DOT to propose a timeline for its response to the Rail Car Petition.[x] According to the briefing schedule, the Ninth Circuit’s ruling will likely come in early 2015.

The second lawsuit targets a permit to transfer crude oil from trains to trucks issued to Inter-State Oil Company, a fuel and lubricants distributor located outside of Sacramento, California.[xi] In this suit, the Sierra Club alleges that the Sacramento Metropolitan Air Quality Management District (“District”) illegally authorized Inter-State’s permit without the requisite public notice and comment in violation of the California Environmental Quality Act (“CEQA”). The Sierra Club asks that the court revoke Inter-State’s permit and declare that the District violated CEQA. This is not the first legal challenge of this nature, however. A San Francisco Superior Court Judge recently dismissed a similar suit against a Kinder Morgan facility outside of Richmond, California, on timeliness grounds.[xii]

Whatever the potential merits of these suits, one theme rings clear: Players in the Bakken will continue to spend time and money overcoming logistical as well as legal obstacles transporting their product to market. On the national level, the DOT will require more stringent mechanical and safety standards for tank cars carrying crude oil. The only uncertainty is when these more stringent standards will be required. If the environmental groups’ recent lawsuits in California indicate a trend, the groups may increasingly target non-railroad midstream and crude end-users under state law.[xiii] An increasing amount of litigation, whether successful or not, could stall new infrastructure development, eventually impacting the demand for Bakken crude.

[i] See Association of American Railroads, Moving Crude Oil by Rail 8 (2014) (“Around 100,000 DOT-111 cars are used to transport crude oil or other flammable liquids.”).

[viii] Id. at 26–27 (citing 5 U.S.C. § 555(b) (2013) (“With due regard for the convenience and necessity of the parties or their representatives and within a reasonable time, each agency shall proceed to conclude a matter presented to it.”)).

]]>http://www.northamericashaleblog.com/2014/10/06/environmental-groups-ramp-up-the-crude-by-rail-fight-in-the-courtroom/feed/0http://www.northamericashaleblog.com/2014/10/06/environmental-groups-ramp-up-the-crude-by-rail-fight-in-the-courtroom/Environmental Group Calls for Tighter Regulation of Frac Sandhttp://feeds.lexblog.com/~r/northamericashaleblog/~3/Ov9W1InCeJA/
http://www.northamericashaleblog.com/2014/09/30/environmental-group-calls-for-tighter-regulation-of-frac-sand/#commentsTue, 30 Sep 2014 18:01:35 +0000http://www.northamericashaleblog.com/?p=2605Continue Reading]]>The U.S. shale boom has generated a boom in a related industry: “frac sand.” Sand has become an integral component of hydraulic fracturing. Oil companies use sand as a “proppant”: after shale formations are injected with water and chemicals, the proppant keeps the newly formed cracks open to allow natural gas or crude oil to escape more easily.

Hydraulic fracturing requires a special kind of sand, which is most commonly found in Wisconsin. This so-called “frac sand” is high quality quartz, which is highly resilient and has spherical grains. It is crush-resistant, and can withstand pressures between 6,000 and 14,000 pounds per square inch. A spike in the demand for frac sand has motivated other states to start producing sand. According to most experts, the best rock units to produce frac sand are the St. Peter Sandstone, Jordan Sandstone, Oil Creek Sandstone and Hickory Sandstone. Wisconsin and Minnesota are the biggest players currently, and have a total of 164 active frac sand facilities, and another 20 that have been proposed.

Over the past year or so, drillers have determined that using larger amounts of sand in hydraulic fracturing can lead to significantly better energy production. In fact, just a year ago, hydraulic fracturing operations used around 2,500 tons of sand per well; today, new hydraulic fracturing techniques call for as much as 8,000 tons to be pumped into one well. To illustrate, 8,000 tons of sand would fill 75-100 railcars. Oil and gas companies are expected to use nearly 95 billion pounds of sand this year, according to the latest report from energy-consulting firm PacWest Consulting Partners. That is up nearly 30% from 2013 and a 50% increase from forecasts made by the firm a year ago.

As the frac sand industry has grown, so too has public concern about its environmental and health effects. An environmental group issued a report last week calling for action by state and local governments to address potential health and environmental risks from frac sand mining. The report noted that currently, “none of the states at the center of the current frac sand mining boom have adopted air quality standards for silica that will adequately protect the tens of thousands of people living or working near the scores of recently opened or proposed mining sites.” In 2012, the National Institute for Occupational Safety and Health identified exposure to airborne silica as a health hazard to some workers conducting some hydraulic fracturing operations. The Occupational Safety and Health Administration (OSHA) has identified a risk of silicosis when workers are exposed to dust with high levels of respirable crystalline silica during hydraulic fracturing. Silica sand mining operations are also subject to OSHA regulations. North America Shale Blog contributor Patricia Poole wrote a post about the OSHA crystalline silica rule in August of last year.

Frac sand-specific air quality standards and other regulations could have a significant impact on the growing frac sand mining industry and the oil and gas industry it services.

]]>http://www.northamericashaleblog.com/2014/09/30/environmental-group-calls-for-tighter-regulation-of-frac-sand/feed/0http://www.northamericashaleblog.com/2014/09/30/environmental-group-calls-for-tighter-regulation-of-frac-sand/Ninth Circuit Upholds TERO Requirements in Indian Country Mineral Leasinghttp://feeds.lexblog.com/~r/northamericashaleblog/~3/J_pDGLDNWNc/
http://www.northamericashaleblog.com/2014/09/29/ninth-circuit-upholds-tero-requirements-in-indian-country-mineral-leasing/#commentsMon, 29 Sep 2014 16:00:42 +0000http://www.northamericashaleblog.com/?p=2601Continue Reading]]>Conducting commercial operations on tribal lands can pose significant challenges for non-Indian companies. Demonstrating sensitivity to the cultural nuances of Native American society and navigating the complex web of federal and tribal regulations applicable to Indian Country requires expertise and invariably adds time and costs to projects. Among the more difficult aspects of operating on tribal lands is managing compliance with applicable tribal preference requirements. These requirements, often expressed through a Tribal Employment Rights Ordinance (“TERO”), require commercial entities doing business in Indian Country to give preference to tribal members and member-owned businesses when making employment and contracting decisions in association with projects conducted on Indian lands.

Although TERO laws are common on Indian reservations around the country, some commentators have questioned the enforceability of TERO provisions, arguing that the preference requirements represent impermissible discrimination on the basis of national origin, a practice that Title VII of the Civil Rights Act of 1964[1] prohibits. On September 26, 2014, the United States Court of Appeals for the Ninth Circuit became the first federal appellate court to address the merits of this question. In EEOC v. Peabody Western Coal Co.,[2] the Ninth Circuit upheld the validity of Navajo hiring preferences in coal leases issued to private companies on the Navajo Nation’s Reservation. In reaching its result, the Ninth Circuit concluded that the Navajo hiring preference in the leases represented a political classification, rather than a classification based on national origin, and therefore did not violate Title VII. While the question remains open in other circuits, most notably in the Eighth and Tenth Circuits (where significant private mineral development is occurring on tribal lands), the decision in Peabody Western is likely to be influential in how tribes apply, and courts interpret, tribal TERO requirements in the future.

I. BACKGROUND.

Those not familiar with federal Indian law might be surprised to learn that common constitutional prohibitions against discrimination either do not apply, or apply in modified form in the context of Indian Country. Most notably, neither the Bill of Rights nor the Fourteenth Amendment apply to tribal governments.[3] Accordingly, the concepts of equal protection and due process lack constitutional force in limiting tribal power.

Tribes are subject, however, to “certain restrictions . . . similar, but not identical, to those contained in the Bill of Rights and the Fourteenth Amendment.”[4] In 1968, Congress passed the Indian Civil Rights Act (“ICRA”).[5] Among other protections, ICRA provides that “[n]o Indian tribe in exercising powers of self-government shall . . . deny to any person within its jurisdiction the equal protection of its laws.”[6]

Whether a TERO Ordinance would violate ICRA’s equal protection clause is an open question. The federal courts have acknowledged that “the standards of analysis developed under the Fourteenth Amendment’s Equal Protection Clause [are] not necessarily controlling in the interpretation of the [ICRA],” recognizing that interpretation of ICRA must account for the unique cultural, historical, and socio-political circumstances of individual tribes.[7] Equally important, the statute itself is not enforceable in federal court; the Supreme Court has held expressly “that suits against the tribe under the ICRA are barred by [the tribe’s] sovereign immunity from suit.”[8]

Nor is it clear that generally applicable statutory limitations on discriminatory business practices apply to Indian tribes or tribal members. “Since 1834, Congress has incorporated employment preferences for Indians into legislation governing Indian programs and services.”[9] Qualified Indians enjoy “the preference to appointment to vacancies” in the Bureau of Indian Affairs and the Indian Health Service.[10] Federal law requires Indian preference — in hiring, training, and subcontracting — on all government contracts “to Indian organizations or for the benefit of Indians.”[11] Title VII itself includes an exception, allowing employers “on or near a reservation” to grant Indians “preferential treatment,” provided the preferential treatment policy has been publicly announced.[12] And in Morton v. Mancari,[13] the United States Supreme Court upheld the constitutionality of Indian preference holding that such preference is premised on a political, rather than racial, distinction and that this distinction was “reasonably designed to further the cause of Indian self-government[,] . . . a legitimate, nonracially based goal.”[14]

II. PEABODY WESTERN.

Notwithstanding the exceptions referenced above, the federal Equal Employment Opportunity Commission (“EEOC”) has adopted the position that a preference for members of a particular tribe — as opposed to a preference for “Indians” generally — falls outside the exemption of Title VII and constitutes unlawful national origin discrimination.[15] In Dawavendewa v. Salt River Project Agricultural Improvement & Power District,[16] the Ninth Circuit adopted a version of EEOC’s position in a case in which members of the Hopi tribe contended that the Navajo Nation’s tribal preference policy resulted in impermissible discrimination against members of other tribes who wished to work on the Navajo Reservation. The Ninth Circuit acknowledged the possibility, holding that “differential employment treatment based on tribal affiliation is actionable as ‘national origin’ discrimination under Title VII.”[17] The Ninth Circuit distinguished Dawavendewa from the Supreme Court’s holding in Morton, explaining that Morton did not involve a challenge under Title VII, and characterized the holding in Morton as limited– in the Ninth Circuit’s view, the Supreme Court in Morton held only that “the employment preference at issue, though based on a racial classification, did not violate the Due Process clause because there was a legitimate non-racial purpose underlying the preference.”[18]

The Peabody Western suit followed Dawavendewa. Peabody Western involves a similar contest to the validity of hiring and contracting preference requirements applicable to Peabody’s operations on coal leases Peabody owns on the Navajo Reservation. Unlike Dawavendewa, where the plaintiffs were Hopi workers who felt that they had been discriminated against, the EEOC is the plaintiff in Peabody Western; the EEOC contends that Peabody’s compliance with the Navajo’s tribal preference requirements violates Title VII.[19]

On October 18, 2012, the United States District Court for the District of Arizona dismissed the EEOC’s claim in PeabodyWestern, upholding the validity of the Navajo’s tribal preference statute. The district court first explained that Dawavendewa was not controlling, observing that, while the Ninth Circuit had ruled in Dawavendewa that discrimination on the basis of tribal membership represented actionable national origin discrimination under the terms of Title VII, the Ninth Circuit had not actually decided the case on the merits and determined that the application of a tribal preference violated Title VII.[20] The district court went on to conclude that while discriminatory, the Navajo’s tribal preference statute was reasonably tailored to “benefit the members of the tribe — a political entity — and to foster tribal self-government and self-sufficiency.”[21] The district court reasoned that, because it is “tribal membership, not status as an Indian, that is the touchstone” of the tribal preference, “[l]ike the general Indian preference in Mancari, the tribe-specific preference . . . is a political classification.”[22]

On September 26, 2014, the Ninth Circuit affirmed the district court. The Ninth Circuit observed that the coal leases at issue in Peabody Western – like virtually all mineral leases executed with tribal entities – were issued under the Indian Mineral Leasing Act of 1938 (“IMLA”),[23] a statute designed “to foster tribal self-determination by giving Indians a greater say in the use and disposition of the resources found on Indian lands.”[24] The Ninth Circuit acknowledged that the Department of the Interior has a long history of approving mineral leases that require the tribe’s lessee to give preference in hiring to tribal members and reasoned that “[t]his long-established practice serves to ensure that the economic value of the mineral leases on tribal lands inures to the benefit of the tribe and its members, consistent with the purpose of the IMLA.”[25]

With the IMLA providing the contextual background, the Ninth Circuit explained that, although discrimination based on tribal membership could implicate rules against national origin discrimination, “[i]n appropriate situations, federal law yields out of respect for treaty rights or the federal policy fostering tribal self-governance.”[26] The Ninth Circuit concluded that the Navajo mineral leasing program was such a situation— the Navajo preference rules advanced the federal policy of promoting Indian self-government and affording the tribe the maximum amount of control over its own natural resources.

That the Navajo preference statute discriminated against members of other Indian tribes was not dispositive, because “[w]here the exploitation of mineral resources on a particular tribe’s reservation is concerned, the federal government’s responsibility necessarily runs to that tribe, not to all Indians.”[27] The Ninth Circuit characterized the preferential hiring provisions in Peabody’s leases as “useful in ensuring that the economic benefits flowing from the ‘most important resource’ on the Navajo reservation accrued to the tribe and its members” and summarized that “[m]easures intended to preserve for the Nation and its members the fruits of the resources found on the tribe’s own land are “rationally designed” to fulfill the federal government’s trust obligations to the tribe.”[28]

III. CONCLUSION.

Although the Ninth Circuit’s opinion in Peabody Western appears to grant broad support for the enforceability of TERO statutes, several essential questions still remain to be resolved. First, although all mineral leases executed on tribal lands are granted under the IMLA, leases executed with individual allottees are not. Those leases are typically executed under the authority of 25 U.S.C. § 396, a statute that courts may not interpret to reflect the same underlying objectives related to tribal self-determination and sovereignty that the IMLA advances. Whether the Ninth Circuit’s rationale in Peabody Western can be applied to allottee lands therefore remains to be decided.

It is also unclear what influence that the Ninth Circuit’s decision will have on courts that might address similar questions in the next few years. While coal continues to dominate on the Navajo Reservation, significant oil and gas activity continues to proliferate on tribal lands in, among other places, North Dakota, Utah, Colorado, New Mexico, and Oklahoma. The Peabody Western decision is not controlling in any of those locations. In the end, prudent companies will continue to comply with all federal and tribal preference restrictions, but important questions about the long term enforceability of TERO programs remain.

[1] 42 U.S.C. § 2000e-2.

[2] No. 12-17780 (9th Cir.).

[3] See, e.g., Talton v. Mayes, 163 U.S. 375, 384 (1897) (holding that the Fifth Amendment did not restrict the power of local tribal governments); Barta v. Oglala Sioux Tribe of Pine Ridge Reservation of S.D., 259 F.2d 553, 556 (8th Cir. 1958) (concluding that the Fourteenth Amendment did not restrict Indian tribes).

[4] Santa Clara Pueblo v. Martinez, 436 U.S. 49, 57 (1978).

[5] 25 U.S.C. §§ 1301-03.

[6] 25 U.S.C. § 1302(8).

[7] Santa Clara, 436 U.S. at 55; see also Tom v. Sutton, 533 F.2d 1101, 1104 n.5 (9th Cir. 1976) (“[C]ourts have been careful to construe the terms ‘due process’ and ‘equal protection’ as used in the Indian Bill of Rights with due regard for the historical, governmental and cultural values of an Indian tribe.”).

[12] 42 U.S.C. § 2000e-2(i). Indian Tribes themselves are also exempted from the definition of “employer” for purposes of Title VII. 25 U.S.C. § 2000e(b).

[13] 417 U.S. 535 (1974).

[14] Id. at 554.

[15] See Cohen’s Handbook § 21.02[5][c][ii].

[16] 154 F.3d 1117 (9th Cir. 1998).

[17] Id. at 1120.

[18] Id. The subsequent history in Dawavendewa is nevertheless notable because it reflects the procedural hurdles a party wishing to contest the validity of tribal preferences must overcome (in addition to the substantive challenge of proving the law invalid on the merits). Although the Ninth Circuit ruled that a plaintiff could challenge the Navajo tribal preference policy under Title VII, the plaintiffs’ action in Dawavendewa ultimately failed on a procedural ground. In a later opinion, the Ninth Circuit dismissed the matter after determining that the Navajo Nation would be an indispensable party in the plaintiffs’ suit against the private employer, but that the Nation could not be joined because it had not waived its sovereign immunity. See Dawavendewa v. Salt River Project Agric. Improvement & Power Dist.,276 F.3d 1150, 1153 (9th Cir. 2002).

[19] The Ninth Circuit permitted the Peabody Western suit to proceed on the theory that tribal sovereign immunity was inapplicable when a federal agency’s suit did not seek to hold the tribe liable, but was merely seeking to join the tribe to provide complete and effective relief to a party. SeeEEOC v. Peabody W. Coal Co, 400 F.3d 774, 778 (9th Cir. 2005). It remains unclear whether a private party could pursue such a lawsuit without the participation of the EEOC or some other federal entity.